Annual Report 2021 Focused on delivering Beach Energy Limited ABN 20 007 617 969 Beach Energy Annual Report 2021 About this report About Beach Energy FY21 Performance Highlights Operations portfolio Our journey over 60 years Chairman’s letter Managing Director’s letter Executive team Our markets Our strategy Operating review Reserves statement Sustainability Board of directors Full Financial Report Directors’ report Auditor’s independence declaration 2021 Remuneration in brief (unaudited) Remuneration report Directors’ declaration Financial statements Notes to the financial statements Independent auditor’s report Additional Information Glossary Schedule of tenements Shareholder information Corporate information & directory IFC 02 03 04 06 08 10 12 14 16 17 32 38 40 43 44 59 60 62 79 80 84 125 130 132 137 BC Cover: Bass Basin, VIC About this Report This 2021 Annual Report is a summary of Beach Energy’s operations and activities for the 12 month period ended 30 June 2021 and financial position as at 30 June 2021. 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. See Glossary for further defined terms used in this report. This report contains forward-looking statements. Please refer to page 51, 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 2021 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 SA 5000 Date: Wednesday, 10 November 2021 Please note, the Annual General Meeting format will be subject to COVID safety requirements. For more information, visit: www.beachenergy.com.au/agm Our Vision We aim to be Australia’s premier multi-basin upstream oil and gas company. Our Purpose Sustainably deliver energy for communities. Our Values Our values define us, guide our actions, our decisions and our words. 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 Otway Basin, VIC 01 Beach Energy Limited Annual Report 2021 About Beach Energy Focused on sustainably delivering energy for communities. Beach Energy is an ASX listed, oil and gas exploration and production company headquartered in Adelaide, South Australia. Beach’s purpose to ‘sustainably deliver energy for communities’ means it operates while maintaining the highest health, safety and environmental standards. Founded in 1961 and now in its 60th year, Beach today has oil and gas production in five basins across Australia and New Zealand and is a key supplier of gas into 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. Beach operates a world-class onshore oil business on the Western Flank of the Cooper Basin and has grown to become Australia’s largest onshore oil producer. In addition to its producing assets, Beach has a suite of exploration permits across the onshore Cooper and Perth basins, onshore and offshore Otway Basin as well as offshore acreage in the Bonaparte (Australia) and Taranaki (New Zealand) basins. Beach is also planning to enter global LNG markets in H2 2023, when it will commence export of its share of LNG volumes from the Waitsia Gas Project Stage 2 in the Perth Basin, operated by JV participant Mitsui E&P Australia (MEPAU), through the North West Shelf infrastructure in Karratha. Beach continues to pursue growth opportunities within Australia and nearby which align with its strategy, satisfy strict capital allocation criteria, and demonstrate clear potential for shareholder value creation. Beach is committed to reducing emissions from its operations, targeting a 25% reduction by FY25, and is also undertaking FEED studies for the proposed Moomba Carbon Capture and Storage Project. Beach is committed to engaging positively with the local communities in which it operates, providing local employment, supply chain opportunities, as well as partnerships with a range of clubs and organisations. (1) Pro forma includes production from the acquisition of Senex Energy’s Cooper Basin and Mitsui’s Bass Basin assets, with an effective date of 1 July 2020. 02 Expanding Natural Gas Portfolio Page 2 Expanding Natural Gas Portfolio In FY21, gas made up 55% of Beach’s total production. Gas 55.4% West Coast 3.1% East Coast 44.5% NZ 7.8% Liquids 44.6% LPG 7.4% Condensate 6.3% Oil 30.9% 25.61 MMboe FY21 Production 25BY 25 Aspiration of net zero by 2050 Beach Energy has announced an aspiration to reach net zero scope 1 and scope 2 emissions by 2050. Several technologies, including carbon capture and storage are needed to achieve this goal. Through its 25 by 25 initiative, Beach is already targeting a 25 per cent reduction in operated emissions by FY25, compared with FY18 levels. Beach has already made strong progress, with projected emissions in FY21, approximately 12 per cent lower when compared to FY18. In FY21, Beach delivered initiatives to reduce flaring at our gas plants and our established Sustainability division will continue to drive and deliver new emissions reductions ideas. Read more about our emissions reduction initiatives on page 38. FY21 Performance Highlights 26.1MMboe $1,519M Sales Volumes Sales Revenue $760M Operating Cash Flow 66% $363M Underlying EBITDAX Revenue Margin Underlying NPAT (1) 71 68 66 560 459 363 339MMboe 2P Reserves 352 339 326 FY19 FY20 FY21 FY19 FY20 FY21 FY19 FY20 FY21 FY21 Summary 2021 was our safest year on record. 25.6 MMboe 105% Increase 133% 99.3% Strength Production of 25.6 MMboe net to Beach Perth Basin production increased 105% – new annual record Three year 2P reserve replacement ratio Otway Gas Plant reliability Financial strength maintained (1) Underlying results in the chart 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 47 for a reconciliation of this information to the financial report 03 Beach Energy Limited Annual Report 2021 A Diverse Operations Portfolio Beach Energy operates a diverse portfolio of assets, spanning onshore and offshore operations across five operating basins. These include production facilities in the Cooper, Bass, Otway (SA & Victoria), Perth and Taranaki Basins. Darwin Cooper Basin Western Flank & Cooper Basin JV (Various operated and non-operated interests) Western Flank Oil & Gas Low-cost operations with unit field operating costs <$6 per boe. Beach now the sole operator across the Western Flank acreage following the $83 million acquisition of Senex Energy’s Cooper Basin portfolio. Middleton gas plant operated at 98.5% reliability. Cooper Basin JV Participated in 43 wells at 84% overall success rate. Commenced FEED activities for the Moomba CCS project. De-bottlenecked the Karmona triplex pipeline supporting additional gas volumes from south west Queensland. Perth Basin Waitsia (Beach 50% non-operated) Beharra Springs (Beach 50% operated) Production increased 105% following successful completion of Waitsia Stage 1A and tie-in of the Beharra Springs Deep 1 exploration well. Reached FID for the Waitsia Gas Project Stage 2 development. Successfully executed key agreements underpinning the Waitsia LNG project. Clough awarded the lump sum engineering, procurement and construction contract for Waitsia gas plant and associated infrastructure. 04 Perth Adelaide SA Otway Basin Katnook (Beach 100% operated) Production increased 77% from FY20. Awarded exploration licence PEL 680 with Cooper Energy. Gas processing facilities Gas production Oil production Exploration Beach office Darwin Brisbane Adelaide Sydney Canberra Penola Melbourne Victorian Otway Basin Otway Gas Project/HBWS (Beach 60% operated) Enterprise 1 nearshore gas discovery yielded 34 MMboe gross 2P gas and associated liquids reserves (20 MMboe net to Beach). Favourable outcome from the Otway Lattice East Coast gas price review. Commenced offshore Otway drilling campaign, with two successful wells (Artisan 1 and Geographe 4) drilled to target depth during the financial year. Artisan 1 offshore gas discovery provides optionality for future Otway Gas Plant backfill. Completed major planned Otway Gas Plant maintenance activity on time and within budget. 99.3% reliability at Otway Gas Plant Bass Basin BassGas (Beach 88.75% operated) Completed the acquisition of all MEPAU’s Bass Basin interests. Completed comprehensive Concept Select and entered FEED phase for the Trefoil development project. Hobart Taranaki Basin Kupe (Beach 50% operated) No recordable safety incidents encountered throughout the Kupe compressor project. Approximately 98.5% reliability at the Beach-operated Kupe facility. New Plymouth Wellington Illustration not to scale. 05 Beach Energy Limited Annual Report 2021 Our Journey over 60 Years 2021 marks 60 years since Dr Reg Sprigg incorporated Beach Petroleum, drilling the first well in the beachside suburbs of Adelaide – giving rise to the company today known as Beach Energy. Since that time, Beach has grown to become one of Australia’s leading energy producing companies, and today has operations in five producing basins across Australia and New Zealand. A string of successful Cooper/ Eromanga Basin oil discoveries deliver growth – 1985 In the early 1980s, Beach made oil discoveries at Jackson, Bodalla South and Kenmore in south-western Queensland. Beach makes a commercial gas discovery in Victorian Otway Basin – 1979 Beach Petroleum’s first well, named Grange 1, is drilled in the Adelaide beachside suburb of Grange. The well is now the location of the Grange Golf Course – 1962 Beach Petroleum is incorporated by South Australian geologist and conservationist, Dr Reg Sprigg – 1961 1960 06 1970 1980 5 basins Major acquisition of Lattice Energy results in significant diversification, taking Beach from one operating basin to five – 2018 1 MMboe Following earlier commercial discoveries in the Cooper Basin, Beach’s annual production reaches 1m boe – 2005 Acquisition of Drillsearch This acquisition consolidates Beach’s position as a key Cooper Basin producer – 2016 Proudly South Australian Beach returns to South Australia, consolidates its financial position, and expands its operations with a focus on the Cooper/Eromanga Basin. 60 Years Beach celebrates 60th Anniversary – 2021 >$1 billion Beach embarks on >$1 billion offshore Otway Project, while first LNG volumes are marketed for the Waitsia Gas Project Stage 2 – 2021. Safest year on record Beach records its safest year on record including 3 million hours without a lost time injury – FY21 2000 2010 2020 07 Beach Energy Limited Annual Report 2021 Letter from the Chairman Focused on our stated purpose to “sustainably deliver energy for communities.” Dear Shareholder, This financial year Beach Energy will celebrate its 60th anniversary, having drilled its first well in 1962 at Grange Beach in Adelaide, South Australia. People are at the heart of this and every company. As we turn 60 I take this opportunity to thank all those who have been involved in contributing to Beach, both past and present. Beach today is the sum of all of your contributions which we acknowledge and appreciate. Over the past 60 years, Beach has undergone a significant evolution to become an oil and gas exploration and production company with a broad and diverse portfolio of assets producing energy in five basins across Australia and New Zealand. Today that diverse portfolio and a strong balance sheet gives Beach the right foundation to further develop its assets to deliver sustainable long term growth. We look forward to the development of the portfolio over the next three years and the cash flows that will generate. Throughout FY22 and FY23 we will be investing in our existing assets across all five basins with the aim of sustainably delivering energy for the benefit of our communities and stable long term cash flows for the benefit of our shareholders with delivery of Kupe compression and Geographe gas this financial year, Thylacine gas in FY23 and Waitsia gas in FY24. Achieving this aim sustainably requires us to develop our assets safely. To that end, 2021 saw Beach achieve its safest year-on-record. Three million hours were worked without a lost time injury. That is a great achievement and I thank and congratulate our employees and contractors whilst at the same time asking them to continue their focus on safety. 08 Achieving our aim sustainably also requires us to operate in an environmentally conscious way. In this regard we have achieved our first-year targets for emissions reduction as part of our “25 by 25” initiative as well as deliver the first suite of projects under this program. You will see in our Sustainability Report the company is also taking further steps to achieve its aspiration of decarbonising the business on a net basis by 2050. Financial year 2021 did, however, present challenges for our Western Flank asset. As a result of our drilling program, it was determined that the 2P reserves for Western Flank, previously reported in accordance with PRMS guidelines, were less than anticipated. Reserves changes are not uncommon, but the reduction in reserves was of course disappointing. We are sensitive to the corresponding impact felt by shareholders. A detailed review of the forward plan for the asset has been undertaken and in FY22 we will recommence exploration activity across the Western Flank with the obvious goal of unlocking new reserves. Despite this, the Western Flank remains a key part of our portfolio generating strong margins and cash flow. Your company is in a strong financial position with the assets and work program to deliver increasing value for shareholders in the coming years. I thank shareholders for their continued support as we focus on delivering that program and value. I also thank all of our staff, contractors and stakeholders for their continued dedication to safely delivering sound operational results in FY21. Glenn Davis | Chairman 16 August 2021 Bass Basin, VIC Focused on growth 09 Beach Energy Limited Annual Report 2021 Managing Director’s Letter Our Purpose at Beach Energy is to ‘Sustainably deliver energy for communities’, and in FY21, our efforts to drive down emissions from our operations shifted up several gears. Of all the highlights from FY21, nothing gives me greater satisfaction than to say that our team made it our safest year on record. Beach’s Total Recordable Injury Frequency Rate (TRIFR) of 2.1 was a 40 per cent improvement from FY20. Furthermore, Beach also passed a significant milestone of three-million hours without a Lost Time Injury. This is an extraordinary result for our team in our busiest year and with an overlay of the challenges of COVID-19. Our Purpose at Beach Energy is to ‘Sustainably deliver energy for communities’, and in FY21, our efforts to drive down emissions from our operations shifted up several gears. A key element of this is Beach’s newly adopted aspiration to reach net zero Scope 1 and 2 operated emissions by 2050. We set this goal with confidence given our progress on our 25 by 25 target and the capabilities within our business to drive further emissions reduction. In relation to our 25 by 25 initiative – our stated objective to reduce company emissions by 25 per cent by FY25 against FY18 levels – we made some tangible steps toward decarbonisation this year. A key element of this is Beach’s newly adopted aspiration to reach net zero Scope 1 and 2 operated emissions by 2050. An example of one of these projects is the installation of Mercury Removal Facilities at the Otway Gas Plant. This resulted in a reduction in the use of flaring at the plant, and cuts emissions by about 12,000 tonnes over the next decade. It is projects like this that have seen our emissions at the end of FY21 reduce by approximately 12 per cent on the FY18 emissions benchmark. This sees us on track to meet our “25 by 25” target. I look forward to updating our shareholders on more 25 by 25 initiatives as these projects and ideas progress. Separately, we continue to progress the proposed Moomba Carbon Capture and Storage project with operator Santos, which aims to safely and permanently store 1.7 million tonnes of carbon dioxide per year. In a Financial Year which began with a second-wave of COVID-19 in Victoria, our team’s capacity to think creatively in order to deliver on our work program was regularly tested, and the team delivered with flying colours. Dear Shareholder, The 2021 Financial Year was a period in which the team at Beach Energy remained focused on delivering its key growth projects, aligned with our purpose to sustainably deliver energy for communities. It was a year that was not without its challenges, namely our production and reserves downgrade in the Western Flank, which was a disappointing outcome for everyone at Beach. Despite this downgrade, our balance sheet remained well supported through our diversified portfolio – highlighting why our company undertook the Lattice acquisition in 2018. The last year was highlighted by significant milestones from our two major growth projects in the Perth and Victorian Otway basins. In the Perth Basin, Beach reached Final Investment Decision on the Waitsia Gas Project Stage 2. This is a transformational project for Beach that will see our company enter the global LNG market in 2023. While in Victoria, our team commenced the offshore Otway Basin drilling campaign, Beach’s largest ever investment in a single campaign, as we work towards bringing the Otway Gas Plant back toward peak production by 2023. Helping that objective were our two exploration successes in the Otway Basin, with the Enterprise 1 nearshore well delivering an excellent result and the Artisan 1 offshore exploration well providing a future backfill opportunity for the Otway Gas Plant. It was a year which also saw Beach make two strategic bolt-on acquisitions. One expands our operatorship in the Western Flank, while the other increases Beach’s interest in the Bass Basin where we recently commenced FEED activity for the Trefoil project. 10 I am again pleased to say that, at the end of FY21, there had been no cases of COVID-19 infection at any Beach Energy facility or operated drilling site. This is testament to the robust controls implemented by our teams and contractors. The impacts of the pandemic have not subsided, but I’d like to thank the teams for being flexible in adjusting to change and working collaboratively in response to the challenges as they arise. FY21 Review Despite the downgrades in the Western Flank, Beach ends the year with a strong balance sheet, a testament to our strategically diversified portfolio through the 2018 Lattice acquisition. Beach recorded an Underlying NPAT of $363 million and ended the year with net debt of $48 million, net gearing of 1.5% and liquidity of $402 million. Beach’s annual production for FY21 was 25.6 MMboe, down 4% on FY20, largely the result of the declining performance in the Western Flank. There were several key company highlights in FY21, which included: • Reaching Final Investment Decision for Waitsia Gas Project Stage 2 and executed key agreements required to export LNG through North West Shelf from H2 2023 • Commencing the seven-well offshore Otway drilling campaign aiming to re-fill the Otway Gas Plant by mid-FY23 • Two exploration successes, Enterprise 1 and Artisan 1, in nearshore and offshore Otway Basin • Announcing two bolt-on value accretive acquisitions in the Cooper and Bass Basins, which will serve as a platform for future growth • Concluding Cooper and Otway Basin Lattice GSA price reviews with Origin at favourable terms to Beach • Successfully completed expansion of Xyris Production Facility and tied-in Beharra Springs Deep 1, resulting in the doubling of the deliverability of the Perth Basin assets On the operational side of the business, highlights included: • Delivering Beach’s safest year on record with three million hours worked without a Lost Time Injury • Achieving high facility reliability at the Otway Gas plant, which operated at 99.3% reliability, with Kupe and Middleton facilities at 98.5% • Progressing the Kupe compression project to commissioning on budget • The safe and successful completion of 28-day statutory shutdown at the Otway Gas Plant in November 2021, on time and budget despite border restrictions impacting personnel and equipment logistics FY22 Outlook Delivering on our growth projects remains the focus at Beach in FY22, with activity happening in all corners of the business. The Otway Gas Plant will be connected to new supply with the tie-in of the Geographe development wells, with a further four Thylacine development wells being drilled during the year. In the Perth Basin, where along with our JV operator Mitsui, activities will ramp up on the Waitsia Gas Project Stage 2, with construction commencing on the new gas facility and the drilling of our first development wells. In the Cooper Basin, the drill-bit will be very busy again, particularly on the exploration front. On the Western Flank, we are planning a single-rig program, mainly focused on oil and gas exploration. In New Zealand, the Kupe Compression project will come online in the first half of FY22, extending the production life of the facility, as we investigate future drilling opportunities to keep the Kupe plant full. Conclusion 2021 marks 60 years since Reg Sprigg first created Beach Petroleum, the company you know today as Beach Energy. We remain faithful to Dr Sprigg’s legacy – a company with a pioneering spirit. We also continue to grow and evolve into an industry leading exploration and production company, with an increased focus on sustainability. Our company has had some setbacks in FY21, and we don’t hide from that. But if you look across the company today, you will see investment in projects that deliver growth – and that is what we remain focused on in FY22. Matt Kay | Managing Director & Chief Executive Officer 16 August 2021 12,000t Anticipated emission reduction over the next decade due to the installation of Mercury Removal Facilities 11 Beach Energy Limited Annual Report 2021 Executive Team Matthew (Matt) Kay Managing Director & Chief Executive Officer BEc, MBA, FCPA, GAICD Morné Engelbrecht Chief Financial Officer BCom (Hons), CA (ANZ & South Africa), MAICD Ian Grant Chief Operating Officer MSc, CMgr FCMI Mr Engelbrecht joined Beach in 2016 as Chief Financial Officer and is responsible for the finance, tax, treasury, IT, contracts & procurement, insurance, internal audit and investor relations functions. 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. He is a Chartered Accountant with more than 20 years’ experience in the oil & gas and resource sectors across various jurisdictions including Australia, South Africa, the United Kingdom, Papua New Guinea and China. He has held various executive, financial, commercial and advisory senior management positions at InterOil, Lihir Gold (Merged with Newcrest), Harmony Gold and PwC. Mr Engelbrecht also has extensive experience in strategy and planning, capital management, debt and equity markets, M&A and joint venture management and operations. 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 safety, operational and commercial performance in both onshore and offshore environments. Mr Kay joined Beach in May 2016 as Chief Executive Officer and was appointed to the Board as Managing Director in February 2019. In November 2018, he was elected to the Australian Petroleum Production & Exploration Association (APPEA) Board. Mr Kay brings 28 years of experience in the Oil and Gas industry to Beach. Before joining Beach, he served as Executive General Manager, Strategy and Commercial at Oil Search, a position he held for two years. In that role he was a member of the Executive team and led the strategy, commercial, supply chain, economics, marketing, M&A and legal functions. Prior to Oil Search, Mr Kay spent 12 years with Woodside Energy in various leadership roles, including Vice President of Corporate Development, General Manager of Production Planning and General Manager of Commercial for Middle East and Africa. In these roles Mr Kay developed extensive leadership skills across LNG, pipeline gas and oil joint ventures, and developments in Australia and internationally. 12 Sam Algar Group Executive Exploration and Subsurface BA (Hons), PhD Thomas Nador Group Executive Development Dr Algar joined Beach in February 2021 and brings over 25 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 ASX listed 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 Nador joined Beach in July 2019 as General Manager, WA Development, representing Beach in the Waitsia Joint Venture. He has over 25 years’ experience in the energy sector at senior management and executive levels. He has held previous roles as Executive Vice President and Country Manager for InterOil in Papua New Guinea, as well as Development Manager, Project Interface Manager and Project Integration Manager for LNG projects at Woodside Energy. Mr Nador holds a Bachelor of Science from the University of WA, a Post Graduate Diploma in Science from Curtin University of Technology and is a Member of the Australian Institute of Company Directors. Lee Marshall Group Executive Corporate Strategy and Commercial BE Commerce (Economics and Finance) Mr Marshall joined Beach in January 2018 as Group Executive Corporate Strategy and Commercial. Prior to joining Beach, Mr Marshall was most recently General Manager UK for Woodside Energy. Based in London, Mr Marshall managed exploration assets and business development opportunities in the Atlantic Basin and Africa. He has over 20 years of Australian and global commercial, business development and financial management experience across upstream oil and gas and LNG. Mr Marshall is responsible for upstream commercial, strategy, economics, M&A, business development and marketing. Sheree Ford General Counsel BA, LLB, MBA Brett Doherty Group Executive Health, Safety, Environment and Risk BEng (Electrical), LLB (Hons) Lesley Adams Group Executive, Human Resources Ms Ford joined Beach in March 2018 bringing over 25 years’ experience as a corporate lawyer primarily in the upstream oil and gas industry. Prior to joining Beach, Ms Ford worked for over 10 years as in house counsel at BHP Limited, primarily in the oil and gas business and was General Counsel and Company Secretary at listed and privately owned oil and gas companies including InterOil Corporation, Oil Search Limited and Roc Company Limited. As well as extensive experience in upstream oil and gas business across Australia, Asia, Africa and the United Kingdom, Ms Ford has been involved in numerous large company transactions including M&A. 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 Adams commenced with Beach in October 2019. She is an experienced executive with more than 25 years’ experience within the international and Australian oil and gas industry, with business experience in Human Resources, Continuous Improvement, Strategic Planning, Joint Venture Management, Emergency Management, Sustainability, Indigenous and Government Affairs and M&A. Prior to Beach, Ms Adams was Group Executive Corporate Services for Quadrant Energy and assisted the integration post-acquisition by Santos Ltd. Lesley has previously worked for Santos, Woodside, AMEC and Schlumberger. Ms Adams is passionate about employee engagement and empowerment to drive results. 13 Beach Energy Limited Annual Report 2021 Our Markets Focused on four key gas markets. LNG market New Zealand gas market • In FY21, Beach took FID on the Waitsia Stage 2 Gas Project, which will see Beach become Australia’s newest LNG participant. • Beach is actively marketing its 50% share of 7.5 million tonnes of LNG over a five-year period from H2 2023. • Global LNG trade increased 0.4% in 2020, despite the impact of COVID-19 on global economic activity. • LNG market is emerging from recent oversupply, with JKM spot pricing reaching an all-time high of US$32.50 per MMBtu during northern summer period and LNG forward curves rising over the last 3 – 6 months. • Beach operated Kupe gas facility supports approximately 15% of New Zealand’s domestic market. • New Zealand domestic market tightened during FY21 due to declining production from other local fields and lower than average hydroelectric storage levels driving gas demand for thermal power generation. • Kupe compressor project is expected be completed in H1 FY22 to support plateau production rates at the plant’s capacity until mid-FY24. • Beach’s share of Kupe gas production remains fully contracted until September 2024. Taranaki Basin Actively marketing net share of Waitsia LNG from H2 2023. 14 West Coast gas market East Coast gas market Perth Basin • Beach and our joint venture participant MEPAU are currently supplying ~40 TJ per day (~15 PJ per annum) (gross) through the Xyris gas facility and Beharra Springs gas facility into the West Coast domestic market, which will continue throughout the LNG export period. • 50% of Waitsia 2P gas reserves available to supply up to 250 TJ per day to the domestic gas market from 2029. • Tightening West Coast gas market supported by reduced NWS domestic gas supply and increasing customer demand. • Waitsia JV supporting transition to low emission fuel in WA’s Mid-West region with signing of gas supply agreement with Clean Energy Fuels Australia. West Coast gas market (PJ) 1,600 1,400 1,200 1,000 800 600 400 200 0 SA Otway Basin Victorian Otway Basin Bass Basin • Increased exposure to the East Coast gas market was an important strategic element for the 2018 Lattice acquisition. • Beach supplied ~12% of domestic East Coast gas volumes during 2020. • Beach and JV participants spending more than $1 billion in exploration and development capital to re-fill the Otway Gas Plant. • ACCC and AEMO forecast market shortfall during mid-2020s. AEMO forecast winter shortfalls by as early as 2023, with signs of tight winter supply already emerging this year. • Majority of Beach’s East Coast gas volumes contracted, with next major re-pricing event from 1 July 2023, similar time to the gas shortfall anticipated by AEMO. • Additional exposure to East Coast gas dynamics with uncontracted gas reserves at Enterprise, Artisan and Trefoil. Page 14 East Coast gas Forecast gas supply – 2020 to 2039 volumes contracted (PJ per annum) 2,500 2,000 1,500 1,000 500 0 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 Source: AEMO WA Gas Statement of Opportunities (December 2020) 0 2 0 2 1 2 0 2 2 2 0 2 3 2 0 2 4 2 0 2 5 2 0 2 6 2 0 2 7 2 0 2 8 2 0 2 9 2 0 2 0 3 0 2 1 3 0 2 2 3 0 2 3 3 0 2 4 3 0 2 5 3 0 2 6 3 0 2 7 3 0 2 8 3 0 2 9 3 0 2 Potential Gas supply (existing) Waitsia Gorgon (tranche 2) Source: AEMO Gas Statement of Opportunities (March 2021) West Erregulla Demand (High) Scarborough Developed Committed Anticipated Demand (Base) Demand (Low) Forecast demand 15 Beach Energy Limited Annual Report 2021 Our Strategy We continue to execute and deliver against our well defined strategy. Optimise core producing assets • Delivered Beach’s safest year on record achieving three million hours worked since the last lost time injury • Otway Gas Plant operated at 99.3% facility reliability • Kupe facility and Middleton gas facility operated at 98.5% reliability • Successful delivery of statutory shutdown of the Otway Gas Plant during Q2 FY21 • Reached commissioning of Kupe compressor project, with first gas on track for H1 FY22 Strengthen our complimentary gas business • Took FID at Waitsia Stage 2, securing access to international LNG markets through North West Shelf facility from H2 2023 • Made two offshore gas discoveries in the Otway Basin, extending production plateau through the Otway Gas Plant • Commenced offshore Otway development drilling campaign to deliver Otway Gas Plant to capacity by mid-FY23 • Completed Xyris facility expansion and Beharra Springs facility upgrade, expanding Perth Basin capacity to 40 TJ per day and increasing production by ~50% on FY20 Maintain financial strength • Prudent balance sheet management and diversification strategy supported Beach through unexpected production decline • Net debt position of $48 million at 30 June 2021, with $402 million liquidity • Net gearing of 1.5% • Earnings stability from our mostly fixed-price, CPI-linked gas business contributed ~40% of FY21 revenue Our people and culture • Supported staff wellbeing throughout pandemic by an increased focus on resilience training and support for leadership Instituted a new Flexible Work Arrangements procedure, supporting diversity and inclusion at work • • Launched a Team Volunteering program to support staff committing up to two days paid time to support recognised charities • Delivered $1.2 million in support through community partnerships including Royal Flying Doctor Service (SA/NT), South Australia Museum, as well as a range of local community clubs and organisations Pursue other compatible growth opportunities • Completed acquisition of Senex Energy’s Cooper Basin assets for $83 million, delivering Beach sole operatorship of the Western Flank infrastructure • Announced the acquisition of MEPAU’s Bass Basin interests, including the producing BassGas assets and Trefoil development • Completed comprehensive ‘Concept Select’ phase and entered Define phase for Trefoil development 16 Operating Review Performance overview Name Production 2P reserves 2C contingent resource Sales revenue Net profit after tax Underlying net profit after tax 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 Western Flank Cooper Basin JV Other Cooper Basin SA Otway Perth Basin SAWA Vic Otway Bass Basin Victoria New Zealand Total Production MMboe MMboe MMboe $ million $ million $ million cps cps $ million FY17 10.6 75 153 653 388 162 20.4 8.5 319 FY18 19.0 313 207 FY19 29.4 326 185 FY20 26.7 352 180 1,251 1,925 1,650 199 302 9.2 13.9 663 577 560 25.4 24.6 1,038 2,374 499 459 21.9 20.2 874 FY21 25.6 339 191 1,519 317 363 13.9 15.9 760 $ million 1,402 1,838 $ million (198) % cents million $ $ million n/a 2.0 1,874 0.575 1,077 639 25.9 2.0 2,277 1.755 3,995 FY20 Oil equivalent (MMboe) FY21 Oil (MMbbl) Gas liquids (MMboe) 9.6 8.7 0.1 0.2 0.4 18.9 3.6 1.4 5.0 2.8 6.7 1.1 0.0 – – 7.9 – – – – 26.7 7.9 0.7 1.3 0.0 0.0 0.0 2.0 0.4 0.5 0.8 0.8 3.6 2,818 3,088 (172) (50) n/a 2.0 2,278 1.985 4,522 n/a 2.0 2,281 1.520 3,467 48 1.5 2.0 2,281 1.240 2,829 Gas (PJ) 8.9 33.3 0.3 1.7 4.7 48.8 14.1 8.1 22.2 11.5 82.5 Oil Equivalent (MMboe) Year-on-year change (%) 8.9 8.1 0.1 0.3 0.8 18.2 2.8 1.9 4.7 2.7 25.6 (7%) (7%) 36% 77% 105% (4%) (22%) 34% (7%) (3%) (4%) 17 Beach Energy Limited Annual Report 2021 Bass Basin, VIC Operating Review Beach remains well positioned to fund our future growth endeavours. Finance FY21 demonstrated the importance of the Lattice acquisition strategy in diversifying the business from Cooper Basin single asset exposure into multiple production hubs across Australia and New Zealand. The downgrade in the Western Flank experienced during the year highlighted Beach’s prudent capital management and focus on maintaining a strong balance sheet, which has allowed us to withstand this adverse event. We have continued to maintain an impressive balance sheet, despite these challenges, ending the financial year with $48 million net debt and net gearing of 1.5%, while boasting liquidity of $402 million. This was despite the $83 million acquisition of the value accretive Cooper Basin assets from Senex, which completed in March 2021. The stable earnings from our mostly fixed-price, CPI-linked gas business, which contributed ~40% of our FY21 revenue, resulted in Beach delivering within our original FY21 underlying EBITDA forecast of $900 – 1,000 million. These stable gas earnings are expected to be further supported in coming years following two favourable re-pricing events on our Lattice Cooper Basin and Otway Basin gas contracts and growth in gas production. Our business remains well positioned to fund our future growth endeavours, including the committed capital towards the offshore Otway drilling program in Victoria and Waitsia Stage 2 project in Western Australia. These two projects are expected to deliver significant uplift in gas production to Beach, supporting stable, long-life revenue generation. Beach remains a growth orientated business with free cash flow prioritised towards our existing portfolio of organic growth projects. Several of these projects are currently in execution phase, which plans to deliver production and revenue growth upon completion from mid-FY23. We continue to take a measured and prudent assessment of inorganic growth opportunities throughout Australia and New Zealand. In FY21, we announced two strategic bolt-on acquisitions, which lay the foundations for future growth, specifically within the Bass Basin with the Trefoil development, which plans to return the Lang Lang Gas Plant to capacity from mid-FY25. 18 Focused on future growth 19 Beach Energy Limited Annual Report 2021 Operating Review Victorian Otway Basin FY21 Highlights • Enterprise 1 nearshore gas discovery yielded 34 MMboe gross 2P gas and associated liquids reserves (20 MMboe net to Beach). • Positive outcome from the Otway gas price review arbitration. • Commenced offshore Otway drilling campaign, with two successful wells drilled to target depth during the financial year. • Artisan 1 offshore gas discovery provides future Otway Gas Plant backfill opportunity. • Completed major planned Otway Gas Plant maintenance activity on time and within budget. • 99.3% reliability at the Otway Gas Plant FY22 Focus • Complete drilling of Geographe 5 and tie-in of the two Geographe development gas wells to the Otway Gas Plant. First production expected in mid-FY22. • Drill four Thylacine development gas wells. • Progress tie-back of Enterprise gas field to the Otway Gas Plant to FID. Operations Victorian Otway Basin FY21 Production FY21 Production Victorian Otway Basin 2P Reserves 2P Reserves 2.8MMboe 70MMboe 11% of Beach total 21% of Beach total 20 Operations Victorian Otway Basin operations contributed 11% of Beach’s FY21 production. Net production was 2.8 MMboe, down 22% from FY20 due to major planned maintenance activities at the Otway Gas Plant in November 2020 and reduced customer nominations. The fields produced 14.1 PJ of net sales gas to Beach sold under contract, representing 21% of Beach’s East Coast gas market exposure. Development Beach and its joint venture participant O.G. Energy are investing more than $1 billion in the Otway Basin to support extended operations at the Otway Gas Plant and supply much needed gas volumes into Australia’s East Coast gas market. During FY21, Beach commenced the offshore Otway drilling campaign, one of the key pillars driving the delivery of the Company’s growth strategy. The project aims to commercialise gas and associated liquids reserves within the currently producing Thylacine and Geographe gas fields. The development is targeting to re-fill the Otway Gas Plant by mid-FY23. The development encompasses two additional phases to the Otway Gas Project. This includes the drilling, completion and tie-in of two infield development wells at the Geographe gas field, with production expected to commence in mid-FY22 and the drilling, completion and tie-in of four (two lateral) infield development wells at the Thylacine gas field, with production expected to commence in FY23. At the end of the financial year, Beach had completed extended reach drilling activities at Geographe 4, placed subsea xmas trees at both Geographe 4 and Geographe 5 top-hole locations, and commenced drilling operations at Geographe 5. Beach plans to complete the Geographe 5 deviated section in early FY22 before moving the rig to the Thylacine field to carry out further development drilling. Beach also plans to continue progressing the Front-End Engineering Design (FEED) works associated with the connection of the newly discovered Enterprise gas field, located in the nearshore Otway Basin, to the Otway Gas Plant during FY22. Production from Enterprise is expected to commence during H2 FY23. Beach drilled two successful exploration wells within the Victorian Otway Basin during FY21. Exploration and Appraisal Beach drilled two successful exploration wells within the Victorian Otway Basin during FY21. The discovery of the nearshore Enterprise gas field was announced in November 2020 and resulted in the booking of 34 MMboe gross 2P gas and associated liquids reserves (20 MMboe net to Beach), including 161 PJ gross sales gas (97 PJ net to Beach), within the Upper Waarre formation. Importantly, the field yielded materially higher liquids than pre-drill expectation and de-risks additional nearshore opportunities in close proximity to the Otway Gas Plant. In March 2021, Beach announced the discovery of the Artisan offshore gas discovery. The well was suspended for future completion and production through the Otway Gas Plant beyond FY25. In July 2020, Beach was awarded VIC/P007192(v) in the nearshore Victorian Otway, adjacent to VIC/P42(v) which hosts the Enterprise gas discovery. The permit was subsequently sold down to joint venture participant O.G. Energy, aligning interest in the Otway Basin. The selldown remains subject to government approval. Commercial In April 2021, Beach announced a positive outcome in respect to the arbitration relating to the re-pricing of Victorian Otway gas sales under the existing Lattice GSA (i.e. excluding the GSA for the sale of gas from the 5% interest previously held by Toyota Tsusho). The redetermined price applies from 1 July 2020, with the required true-up payment received during the fourth quarter. The next re-pricing event will occur on 1 July 2023. Description Victorian Otway Basin (Beach 60% and operator, O.G. Energy 40%) includes producing licences VIC/L1(v) which contains Halladale, Black Watch and Speculant nearshore gas field and licences VIC/L23, T/L2 and T/L3, which contain the Geographe and Thylacine offshore gas fields. Gas from all producing fields is processed at the Otway Gas Plant. The Victorian Otway Basin also includes non-producing nearshore VIC/P42(v), including the Enterprise gas discovery and offshore licences VIC/P43, including the Artisan gas discovery, VIC/P73, including the La Bella gas field (Beach 60% and operator, O.G. Energy 40%), T/30P (Beach 100%). It also includes the nearshore exploration permit VIC/P007192(v) (Beach 60% and operator, O.G. Energy 40%). Diamond Ocean Onyx rig, Courtesy of Diamond Offshore Focused on East Coast gas 21 Beach Energy Limited Annual Report 2021 Operating Review Perth Basin FY21 Highlights • Production increased 105% following successful completion of Waitsia Stage 1A expansion and tie-in of the Beharra Springs Deep 1 exploration well. • Reached FID for the Waitsia Gas Project Stage 2 development. • Successfully executed agreements with NWS, AGIG and WA State Government underpinning the Waitsia LNG project. • Clough awarded the lump sum engineering, procurement and construction contract for Waitsia gas plant and associated infrastructure. FY22 Focus • Commence on-site construction activities for the Waitsia Gas Project Stage 2 gas processing facility. • Commence drilling of up to six conventional Waitsia Stage 2 development wells from H2 FY22. • Target completion of marketing Waitsia LNG volumes, Beach’s first LNG sale. • Progress plans for exploration drilling within EP 320 during FY23. Operations Perth Basin FY21 Production FY21 Production Perth Basin 2P Reserves 2P Reserves 0.8MMboe 100MMboe 3% of Beach total 30% of Beach total 22 Operations Perth Basin operations contributed 3% of Beach’s FY21 production. Net production was 0.8 MMboe, a 105% increase following the completion of the Waitsia Stage 1A expansion project in August 2020 and the tie-in of Beharra Springs Deep in early April 2021. Development The Waitsia Stage 1A expansion of the MEPAU operated Xyris Production Facility was completed during August 2020. The project successfully doubled the capacity of the plant to 20 TJ per day and connected the Waitsia field to the Dampier to Bunbury Natural Gas Pipeline (DBNGP) with the interconnector sized to 280 TJ per day. The additional capacity allows for the future handling of Waitsia Gas Project Stage 2 production. Performance testing at the Xyris Production Facility has resulted in sustained production rates in excess of 20 TJ per day during the second half of the financial year. Activities were also completed at the Beach-operated Beharra Springs Gas Processing Facility with the installation and commissioning of a new cyclonic separator in October 2020. These activities were completed ahead of the April 2021 commencement of production from the recently discovered Beharra Springs Deep field in April 2021. During FY21, the Waitsia Joint Venture reached FID for the Waitsia Gas Project Stage 2 development. The development is a key pillar in Beach’s growth strategy, with production expected to commence in the second half of calendar year 2023. Gas from the Waitsia field will be transported via the DBNGP and processed into liquefied natural gas through the existing North West Shelf infrastructure in Karratha before being exported into international markets. The Waitsia Joint Venture awarded Clough the lump sum engineering, procurement and construction contract for the new 250 TJ per day Gas Processing Facility and associated infrastructure in January 2021. Construction activities are scheduled to commence the first quarter of FY22. The initial phase of the project involves the drilling of up to six development wells, construction of the new 250 TJ per day gas processing facility and associated gas gathering infrastructure. Exploration and Appraisal Interpretation of the Trieste 3D seismic, which covers the Beach operated EP 320, was completed during FY21. The encouraging results have helped define the prospectivity towards the southeast of the Waitsia gas field. During FY22, Beach and its joint venture participant MEPAU will commence planning to drill the exploration commitment well within EP 320. Waitsia, Perth Basin Beach Energy Limited Annual Report 2021 Focused on West Coast growth Commercial During FY21, the Waitsia Joint Venture entered into several key commercial and State Government agreements required to enable FID of Waitsia Stage 2, including: • A Domestic Gas Commitment Agreement and Project Development Deed with the State of Western Australia. • A Gas Processing Agreement, Tie-in Agreement, Production Allocation Agreement and Lifting and Offtake Agreements with the North West Shelf Project participants; and • A Gas Transportation Agreement with AGIG, owner and operator of the DBNGP. Beach commenced marketing activities of the Company’s equity share of up to 7.5 million tonnes of LNG (3.75 million tonnes net to Beach). Volumes will be processed into LNG through the existing North West Shelf infrastructure in Karratha between the second half of 2023 and the end of 2028. At the end of FY21, Beach was conducting discussions with potential buyers and progressing toward contracting LNG volumes during FY22. The Waitsia and Beharra Springs joint venture participants continue to support the Western Australian domestic gas market, entering several Gas Sales Agreements throughout the year for supply during calendar years 2021 and 2022. This is in addition to the announced five-year deal with Clean Energy Fuels Australia (CEFA), which will see Waitsia volumes supply CEFA’s Mid-West LNG Hub project, delivering trucked LNG to customers throughout Western Australia’s Mid-West region. These volumes will support new industry and enable the supply of low GHG emission fuels to energy uses in the region. Description Producing licences areas are Waitsia (Beach 50%, MEPAU 50% and operator) in licence L1/L2 and Beharra Springs (Beach 50% and operator, MEPAU 50%) licences L11 and L22. The exploration permit is EP 320 (Beach 50% and operator, MEPAU 50%). 23 Operating Review Western Flank Oil & Gas FY21 Highlights • Low-cost operation with unit field operating costs <$6 per boe. • Beach now the sole operator across the Western Flank acreage following the $83 million acquisition of Senex Energy’s Cooper Basin portfolio. • Middleton gas plant operated at 98.5% reliability. FY22 Focus • Recommence of drilling activities with single-rig program aimed at reducing decline of Western Flank oil fields and extending plateau gas production through the Middleton gas plant. • Re-focus efforts on development of Birkhead acreage within the ex-Senex Western Flank acreage north of PEL 91. Operations Western Flank Oil and Gas Western Flank Oil and Gas 2P Reserves FY21 Production 2P Reserves FY21 Production 8.9MMboe 35% of Beach total 34MMboe 10% of Beach total1 1. Includes other Cooper Basin/Gemba Reserves 24 Operations Western Flank oil operations accounted for 26% of Beach’s FY21 production. Beach’s share of Western Flank oil production was 6.7 MMboe, down 10% on FY20. This was offset by the acquisition of Senex Energy’s Western Flank interests from 1 March 2021. The average gross daily production rate across the Western Flank oil assets was 17.4 kbopd. Western Flank gas operations accounted for 9% of Beach’s FY21 production. Western Flank gas and associated liquids production was 2.2 MMboe, a 3% increase on FY20. The performance benefited from improved reliability of the Middleton gas plant, which delivered 98.5% during the year. Development Activities during FY21 focused on development drilling across the Western Flank oil fields, predominantly within the Bauer field. Beach drilled and operated a total of 21 Western Flank oil wells during the financial year. This included 11 wells within the Bauer field, three in Kalladeina, two in each of the Hanson, Chiton and Balgowan fields, and a single well in Callawonga. During the FY21, several development oil wells came in below expectation, with higher than expected decline rates. In the Bauer field this was due to higher than forecast interference between wells and water saturations above expectation within several wells. FY21 drilling in non-Bauer fields indicated a lower structural relief and greater complexity than previously modelled. Beach undertook a review of its geological modelling across eight fields outside of Bauer, updating the mapping workflow. This resulted in a 17.6 MMbbl downgrade to Beach’s Western Flank 2P oil reserves which was announced to the market on 30 April 2021. Beach expects to undertake additional development drilling during FY22 across the greater Western Flank acreage. This includes fields acquired from the acquisition of Senex Energy’s Cooper Basin assets, where Beach plans to target development opportunities within the Birkhead reservoir. The review also led to a downgrade of 2P gas and associated liquids reserves within the Western Flank gas acreage by 7.2 MMboe. This was primarily a result of new Lowry production data indicating a lower-than-expected connected gas volume and incorporation of new production and pressure data across seven other fields within ex-PEL 106. Exploration and Appraisal No exploration or appraisal drilling was undertaken during FY21, with focus on high grading oil and gas prospects for the FY22 exploration campaign. Beach has more than 100 prospects and leads across the Western Flank oil and gas acreage and is planning to recommence drilling activities during early FY22. 2.2 MMbbl Western Flank gas and associated liquids production 4% 2021 2.2 | 2020 2.1 Commercial In November 2020, Beach executed an Asset Sale Agreement with Senex Energy to acquire Senex’s Cooper Basin assets for $83 million, with an effective date of 1 July 2020. The acquisition was completed on 1 March 2021 and solidified Beach’s position as the sole operator of all Western Flank oil and gas infrastructure. During the year, Beach executed GSAs with customers for the supply of Western Flank gas in calendar years 2021 and 2022. 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%), ex PEL 91 (Beach 100%) and the Udacha Block – PRL 26 (Beach 100%). Other non-production licences include ex PEL 107 (Beach 100%) and PEL 630 (Beach 50% and operator, Bridgeport 50%). Cooper Basin, SA Focused on exploration 25 Beach Energy Limited Annual Report 2021 Operating Review Cooper Basin JV FY21 Highlights • Participated in 43 wells at 84% overall success rate. • Commenced FEED activities for the Moomba CCS project. • De-bottlenecked the Karmona triplex pipeline supporting additional gas volumes from south west Queensland. FY22 Focus • Four-rig drilling campaign targeting up to 90 wells in FY22. • Plans to commence major central electrification across Cooper Basin JV assets. Operations Cooper Basin JV FY21 Production FY21 Production Cooper Basin JV 2P Reserves 2P Reserves 8.1MMboe 77MMboe 32% of Beach total 23% of Beach total 26 Operations The Cooper Basin joint venture operations contributed 32% of Beach’s FY21 production. Net gas and gas liquids production of 7.0 MMboe was down 6% due to planned and unplanned outages, including compressor downtime at satellite fields, and natural field decline. The operator Santos undertook a comprehensive in-line inspection of the Big Lake to Moomba trunkline to reduce the chance of further unplanned shutdowns. Net oil production of 1.1 MMbbls was down 12% due to natural field decline and weather-related outages. Exploration, appraisal and development Beach participated in 43 Cooper Basin JV wells during FY21, including 40 gas wells (11 exploration, 9 appraisal and 20 development) and 3 oil wells (2 appraisal and 1 development, with an overall success rate of 84%). During the financial year, the joint venture completed de-bottlenecking of Karmona triplex pipeline. The de-bottlenecking activities increased throughput from south west Queensland by approximately 6 mmscf/d (gross) and frees up additional capacity within the Cooper Basin JV system. Commercial Beach and Origin concluded the price review of the Cooper Basin Lattice GSA, which relates to a portion of the gas sold from Beach’s interest in the Cooper Basin JV acquired from Origin Energy in 2017. The agreed new price was completed with favourable terms to Beach and will be applied to gas sold under the Cooper Basin Lattice GSA from 1 July 2021 for a period of three years. During the year, Beach executed GSAs with customers for the supply of uncontracted CBJV gas through calendar years 2021 and 2022. In H2 FY21, Beach executed an agreement with Santos for Beach to undertake FEED activities for the Moomba Capture and Storage (CCS) project. The project aims to use existing infrastructure and depleted fields within the Cooper Basin to initially sequester 1.7 million tonnes of CO2 per annum (gross). In June, the Australian Federal Government awarded the Moomba CCS project funding of $15 million from the Carbon Capture Use and Storage Development Fund and released the public consultation paper regarding CCS methodology. This highlights the Federal Government’s support for the project, which is expected to support approximately 230 new South Australian jobs through construction. Description Beach owns non-operated interest in the South Australian Cooper Basin joint ventures (collectively 33.40% in SA Unit and 27.68% in Patchawarra East), the South West Queensland joint ventures (various interests of 30% to 52.2%) and ATP 299 (Tintaburra) (Beach 40%), which are collectively referred to as the Cooper Basin JV. Santos is the operator. Taranaki Basin FY21 Highlights • No recordable safety incidents encountered throughout the Kupe compressor project. • Approximately 98.5% reliability at the Beach-operated Kupe facility. FY22 Focus • Completion of the Kupe compressor project during H1 FY21. • Evaluation of a potential development well into the Kupe field to extend production plateau beyond FY24. Operations Taranaki Basin FY21 Production FY21 Production 2P Reserves 2.7MMboe 27MMboe 11% of Beach total 8% of Beach total Operations New Zealand operations accounted for 11% of Beach’s FY21 production. Net production was 2.7 MMboe, down 3% over FY20 due to natural field decline. This was offset by improved reliability of the Kupe Production Station, which has delivered 98.5% during FY21. Development, Exploration and Appraisal During FY21, Beach continued to progress the Kupe inlet compression project and despite the global supply chain challenges resulting from COVID-19, the project remains on budget. At the end of the financial year, the project was nearing mechanical completion, with the commencement of commissioning activities in support of project completion in H1 FY22. Beach continues to assess opportunities to extend the 77 TJ per day production plateau beyond FY24. Preparation work for a potential Kupe East development well within the Kupe field is expected to commence during FY22. This could lead to the drilling of a potential development well in FY23, subject to joint venture and regulatory approvals. Beach also continues to assess the value of exploration opportunities that could be drilled from and tied back to the Kupe infrastructure. Further evaluation of a proposed exploration well will be assessed during FY22. Description New Zealand operations comprises Kupe (Beach 50% and operator, Genesis 46%, NZOG 4%) in the Taranaki Basin. Kupe produces gas from the offshore Kupe field, situated approximately 30-kilometres off the New Zealand North Island in licence PML38146. Gas from the Kupe field is then piped to the onshore Kupe production station. 98.5% Kupe Production Station reliability 27 Beach Energy Limited Annual Report 2021 Operations The BassGas Project accounted for 7% of Beach’s FY21 production. Net production from the project was 1.9 MMboe, up 34% on the prior year, following the recognition of the acquisition of MEPAU’s interest in the project from 1 January 2021. This was offset by planned compressor maintenance, unplanned downtime and natural field decline. Development During FY21, Beach continued to assess opportunities to increase the life of the existing BassGas Project infrastructure. The Company completed a comprehensive Concept Select phase for the Trefoil development and proceeded to the Front-End Engineering Design phase in late FY21. The Trefoil development concept comprises two offshore development wells and an approximate 37-kilometre tie-back to Beach’s existing offshore Yolla platform. The concept would allow for the life extension of the Yolla field. Beach is targeting FID in H1 FY23, with potential for first gas in H2 FY25, subject to necessary internal and external approvals. Beach continued to assess upside opportunities from the producing Yolla field, including a three well wireline intervention campaign planned for FY22 and potential infield drilling. Exploration and Appraisal Seismic reprocessing over the Yolla field in FY21 has shown favourable uplift in imaging. During FY22 Beach plans to assess the potential value of additional in-field drilling and in-well optimisation activities to extend production. Planning of the Prion 3D seismic survey covering the White Ibis and Bass discoveries and the Trefoil field continued during FY21. Data is expected to be acquired during FY22, subject to regulatory approvals. The high-resolution 3D seismic data is expected to improve imaging of the Trefoil field and provide a more informed FID for the Trefoil development. Imaging of the White Ibis and Bass discoveries with 3D seismic is aimed at quantifying their potential value as tiebacks into a Trefoil development. Operating Review Bass Basin FY21 Highlights • Announced the acquisition of all MEPAU’s Bass Basin interests. • Completed comprehensive Concept Select and entered FEED phase for the potential Trefoil development project. • Completed emissions reduction project through decreased flaring of off-spec gas during Lang Lang Gas Plant start-up. FY22 Focus • Safely undertake planned major integrity shutdown of the Lang Lang gas facility and Yolla compressor. • Progress FEED studies for the Trefoil development, targeting FID in H1 FY23. • Complete three well wireline intervention campaign within Yolla field. • Undertake 3D seismic acquisition over the White Ibis and Bass discoveries and Trefoil field. • Continue to assess opportunities to extend Yolla field life through wireline intervention and infield drilling. Operations Bass Basin FY21 Production FY21 Production Taranaki Basin 2P Reserves 2P Reserves 1.9MMboe 7% of Beach total 31MMboe 9% of Beach total 28 Bass Basin, VIC Focused on safety Commercial During FY20, Beach entered into an Asset Sale and Purchase Agreement with MEPAU subsidiaries to acquire all its interests in the Bass Basin. These assets include MEPAU’s 35.0% interest in the BassGas Project (comprising the onshore BassGas Plant and offshore Yolla gas field), as well as its 40.0% interest in the Trefoil development project and surrounding retention leases. The terms of the acquisition are confidential and subject to regulatory approvals and third-party consents. The transaction has an effective date of 1 July 2020, and was subsequently completed in July 2021. Description The BassGas Project (Beach 88.75% and operator, Prize Petroleum 11.25%) produces gas from the Yolla field, situated approximately 140 kilometres off the Gippsland coast in licence T/L1. Gas from Yolla is piped to a gas processing facility located near the township of Lang Lang, approximately 70 kilometres southeast of Melbourne. Beach also holds a 90.25% operated interest in licences T/RL2, T/RL3, T/RL4 and T/RL5, which host the Trefoil, White Ibis and Bass gas discoveries. 29 Beach Energy Limited Annual Report 2021 Operations South Australian Otway operations contributed 1% of Beach’s FY21 production. Net production was 0.3 MMboe, up 77% over FY20. Operations at the Katnook Gas Plant are planned to be suspended during H2 FY22 as gas volumes decline below the minimum turndown rate. Development, Exploration and Appraisal Beach plans to conduct a 3D seismic survey over the Dombey gas discovery during FY22 to assess potential of development of this discovery through the Katnook Gas Plant. Beach and Cooper Energy were awarded exploration licence PEL 680 in March 2021. The work commitments under the licence predominantly focus on geological and geophysical studies, with the possibility of 2D seismic acquisition over the initial five-year period. Description SA Otway gas producing area is PPL 62 (Beach 100%). Other licences include PEL 494, which contains the Dombey gas field, PEL 680 and PRL 32 (Beach 70% and operator, Cooper Energy 30%). Beach plans to conduct a 3D seismic survey over the Dombey gas discovery during FY22 to assess potential of development of this discovery through the Katnook Gas Plant. Operating Review South Australian Otway FY21 Highlights • Production increased 77% from FY20. • Awarded exploration licence PEL 680 with Cooper Energy. FY22 Focus • 3D seismic acquisition over the Dombey field to take place during H1 FY22. Operations SA FY21 Production FY21 Production 0.3MMboe 1% of Beach total 30 Frontier Exploration Bonaparte Basin Beach and its joint venture participants (Neptune 54% and operator, Santos 40.25% and Beach 5.75%) continued interpretation of the Petrelex 3D seismic survey over the Petrel gas field. Neptune is progressing the final resource estimate and the development concept, which are expected during FY22. The joint venture was awarded a new exploration permit, WA-545-P, which lies south of the Petrel field. The joint venture was granted two new exploration permits (NT/P88 and WA-548-P) that surround the Petrel gas field and capture the potential extension of the field. Carnarvon Basin The Ironbark gas exploration prospect in exploration permit WA-359-P (BP 42.5% and operator, Cue 21.5%, Beach 21% and NZOG 15%), offshore Carnarvon Basin was drilled to a total depth of 5,618 metres (MD) in Q2 FY21. Logging while drilling data indicated no significant hydrocarbons were present within the primary reservoir. The well was plugged and abandoned and the rig mobilised from site on 11 January 2021. In March, Beach withdrew from the WA-359-P and the joint venture subsequently did not renew the permit. The WA-359-P permit is now expired. Canterbury Basin During FY21, Beach and its joint venture participants applied to surrender exploration permit PEP 52717 (Clipper), which contains the Barque prospect, and PEP 38264, which contains the Wherry prospect, in offshore New Zealand Canterbury Basin. Both submissions to surrender have been approved by the regulator. The decision was made as it was determined that the projects did not meet the risk profile required for frontier exploration expenditure. Great South Basin During FY21, Beach and its joint venture participants submitted an application to surrender PEP 50119 (Tawhaki). This surrender application was granted in FY21. Planning is underway for a regulatory compliance post-drill marine benthic marine survey which is planned for H2 FY22. Kupe, New Zealand Focused on creating value 31 Beach Energy Limited Annual Report 2021 Reserves Statement Net to Beach at 30 June 2021. Beach ended the year with 339 MMboe in 2P oil and gas reserves Beach’s 2P reserves declined by 13 MMboe (-4%) to 339 MMboe at 30 June 2021 due to production of 26 MMboe, a 26 MMboe downgrade within the Western Flank oil and gas assets and re-classification of 5 MMboe at La Bella to 2C contingent resources following exploration success at Enterprise and Artisan. The reductions to 2P reserves were offset by discovery of the Enterprise gas field in the offshore Otway Basin, which added 20 MMboe, and acquisitions of Senex Energy’s Cooper Basin assets and Mitsui’s interests in the Bass Basin, adding 7 MMboe and 14 MMoe respectively. 2C contingent resources increased by 11 MMboe to 191 MMboe (+6%) following acquisition of Mitsui’s interests in the Bass Basin, exploration success at Artisan, re-classification of La Bella reserves and removal of some contingent resources from the Cooper Basin joint venture. Key metrics 1P Reserves 2P Reserves 3P Reserves 2C Contingent Resources Organic 2P reserve replacement ratio Inorganic 2P reserve replacement ratio 2P reserves life (years) 1 2 3 Note FY19 (MMboe) FY20 (MMboe) FY21 (MMboe) 201 326 514 185 204% 141% 12.4 202 352 576 180 214% 200% 13.2 183 339 531 191 (33%) 49% 13.2 1P Reserves (MMboe) 2P Reserves (MMboe) 2P Reserve Life (Years) 190 201 202 183 313 326 352 339 12 11 13 13 38 FY17 FY18 FY19 FY20 FY21 75 FY17 FY18 FY19 FY20 FY21 FY17 FY18 FY19 FY20 FY21 7 32 1P Reserves Note FY20 Production Western Flank Oil Western Flank Gas Cooper Basin JV Perth Basin Otway Basin Bass Basin Taranaki Basin Total 4, 5 5, 6 7 8 9 10, 11 12 24 8 45 55 35 13 22 7 2 8 1 3 2 3 202 26 All products (MMboe) Acquisition/ Divestment Exploration/ Appraisal Contingent Resources to Reserves Other Total Revisions FY21 3 2 – – – 10 – 14 – – 0 – 7 – – 7 (0) (1) 0 – (4) – – (9) (2) (0) (1) 2 (0) 0 (5) (10) (7) (1) 1 (1) 6 9 0 7 10 5 37 54 38 20 19 183 1P Reserves Western Flank Oil Western Flank Gas Cooper Basin JV Perth Basin Otway Basin Bass Basin Taranaki Basin Total Note 4, 5 5, 6 7 8 9 10, 11 12 Gas (PJ) LPG (kt) Condensate (MMbbl) Oil (MMbbl) Total (MMboe) Developed Undeveloped All Products – 18 163 313 185 93 80 – 89 310 – 355 230 350 852 1,334 – 1 3 0 3 3 2 12 10 – 4 – – – – 10 5 37 54 38 20 19 14 183 7 4 33 16 10 2 16 89 3 1 4 37 28 18 3 94 33 Beach Energy Limited Annual Report 2021 Reserves Statement 2P Reserves Note FY20 Production Western Flank Oil Western Flank Gas Cooper Basin JV Perth Basin Otway Basin Bass Basin Taranaki Basin Total 4, 5 5, 6 7 8 9 10, 11 12 46 16 85 101 56 19 29 7 2 8 1 3 2 3 352 26 All products (MMboe) Acquisition/ Divestment Exploration/ Appraisal Contingent Resources to Reserves Other Total Revisions 5 2 – – – 14 – 21 – – 0 – 20 – – 20 (1) (2) 1 – (5) – – (17) (6) (1) (0) 2 0 0 (7) (22) (13) (5) 0 (0) 17 14 0 13 FY21 26 8 77 100 70 31 27 339 Note 4, 5 5, 6 7 8 9 10, 11 12 Gas (PJ) – 31 341 583 346 141 113 LPG (kt) Condensate (MMbbl) Oil (MMbbl) Total (MMboe) Developed Undeveloped All Products – 151 631 – 652 358 494 – 2 6 0 5 4 3 26 – 8 – – – – 26 8 77 100 70 31 27 339 20 7 60 23 10 4 22 6 1 17 77 59 27 5 146 193 1,555 2,285 20 34 2P Reserves Western Flank Oil Western Flank Gas Cooper Basin JV Perth Basin Otway Basin Bass Basin Taranaki Basin Total 34 Beach Energy Limited Annual Report 2021 2C Contingent Resources FY20 (MMboe) Note Reserves to Contingent Resources (MMboe) Acquisition/ Divestment (MMboe) Revisions (MMboe) FY21 (MMboe) Gas (PJ) LPG (kt) Condensate (MMbbl) Oil (MMbbl) Total (MMboe) 5 1 60 39 19 5 6 23 157 14 23 180 Western Flank Oil Western Flank Gas Cooper Basin JV Perth Basin Otway Basin 4, 5 5, 6 7 8 9 Bass Basin 10, 11 Taranaki Basin Bonaparte Basin 12 13 Total Conventional 2C Contingent Resources Cooper Basin JV (unconventional) Total 2C Contingent Resources Notes 3 0 – – – 4 – – 7 – 7 (1) (2) 1 – (5) – – – 3 (1) 0 (0) 7 1 (1) – 12 2 59 38 31 10 5 23 – 6 246 222 168 34 18 128 – 27 230 – 147 146 78 – (7) 8 179 823 628 – (11) 12 42 205 – 0 2 0 0 3 1 1 8 3 12 – 13 – – – – – 12 2 59 38 31 10 5 23 25 179 – 12 (7) (3) 191 866 832 11 25 191 FY21 organic 2P reserves replacement ratio calculated as 2P reserves reduction of 8.5 MMboe divided by FY21 reported production of 25.6 MMboe. (1) (2) FY21 inorganic 2P reserves replacement ratio calculated as 2P reserves additions of 12.6 MMboe divided by FY21 reported production of 25.6 MMboe. (3) FY21 2P reserves life calculated as 339.3 MMboe divided by FY21 production of 25.6 MMboe. (4) Western Flank Oil comprises ex PEL 91 (Beach 100%), ex PEL 92 (Beach 75%), ex PEL 104/111 (Beach 100%), PPL 207 (Beach 70%) and PEL 113/115/516/90/93 and PRL 83 (Beach 100%). 1P reserves at 30 June 2021 are split ex PEL 91 (56%), ex PEL 92 (21%), ex PEL104/111 (22%) and other (1%). 2P reserves at 30 June 2021 are split ex PEL 91 (60%), ex PEL 92 (18%), ex PEL 104/111 (22%) and other (1%). (5) Acquisition of Senex Cooper Basin assets increased equity from 40% to 100% in ex PEL 104/111 and from 43% to 100% in PRL 135 (Vanessa). New permits include 70% in PPL 207 (Worrior), 100% in PEL 113/115/516/90/93, PRL 83 and PPL 270 (Gemba). The effective date of the acquisition is 1 July 2020. Refer ASX announcement #037/20, 3 November 2020. (6) Western Flank Gas comprises ex PEL 106/91 (Beach 100%), PRL 135 and PPL 270 (Beach 100%). 1P reserves at 30 June 2021 are split ex PEL 106/91 (79%), PPL 270 (21%). 2P reserves at 30 June 2021 are split ex PEL 106/91 (82%), PPL 270 (18%). (7) Cooper Basin JV comprises the South Australian Cooper Basin joint ventures (Beach 27.68% and 33.4%), the South West Queensland joint ventures (Beach 20.76% to 45%), SWJV and Tintaburra JV (Beach 40%). (8) Perth Basin comprises Waitsia (Beach 50%) and Beharra Springs (Beach 50%). (9) Otway Basin comprises Thylacine, Geographe, Artisan, La Bella, Halladale, Black Watch, Speculant and Enterprise (Beach 60%) and Haselgrove (Beach 100%). 1P reserves at 30 June 2021 are split Thylacine and Geographe (74%) and Halladale, Black Watch, Speculant, Enterprise (26%). 2P reserves at 30 June 2021 are split Thylacine and Geographe (66%) and Halladale, Black Watch, Speculant, Enterprise (34%). (10) Bass Basin comprises Yolla (Beach 88.75%) and Trefoil, White Ibis (Beach 90.25%). (11) Acquisition of Mitsui’s equity in Bass Basin assets increased equity from 53.75% to 88.75% in T/L1 (Yolla) and from 50.25% to 90.25% in T/RL2 and T/RL4 (Trefoil and White Ibis). The effective date of the acquisition is 1 July 2020. Refer ASX announcement #002, 27 January 2021. (12) Taranaki Basin comprises Kupe (Beach 50%). (13) Bonaparte Basin comprises Petrel (Beach 5.75%). (14) Cooper Basin JV (unconventional) includes the South Australian Cooper Basin joint ventures (Beach 27.68% and 33.4%) classified as unconventional. 35 Material Reserves Changes Beach has previously disclosed material reserves changes throughout the year in accordance with continuous disclosure obligations. These included: • Acquisition of Senex Energy’s Cooper Basin assets (refer to ASX Announcement #037/21 (3 November 2020): “Beach expands Cooper Basin portfolio”). • Acquisition of Mitsui’s Bass Basin interest • (refer to ASX Announcement #002/21 (27 January 2021): “FY21 Second Quarter Activities Report”). Initial Report of Enterprise 2P Reserves (refer to ASX Announcement #004/21 (15 February 2021): “Enterprise Exploration Success Delivers Material 2P Reserves Booking”). • Western Flank 2P oil and gas reserves downgrade (refer to ASX Announcement #013/21 (30 April 2021): “Business Update”). Material Contingent Resources Changes There are no material contingent resources changes. Reserves Statement Notes to the Reserves Statement The reserves and resources estimates are prepared 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 and Society of Petroleum Evaluation Engineers (SPE-PRMS). The statement presents Beach’s net economic interest estimated at 30 June 2021 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 defined by the custody transfer point of each product, with the exception of Waitsia reserves, which include 3.4 MMboe of fuel used for LNG processing through the NWS facilities in Karratha between the second half of 2023 and 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 Ian Cockerill, Scott Delaney, Mark Sales and Jason Storey, who are all members of the SPE. The reserves statement as a whole is approved by Ms Paula Pedler (Head of Reservoir Engineering). Ms Pedler is an employee of Beach and a member of the SPE; she has a Bachelor of Engineering (Honours) from the University of Adelaide and in excess of 25 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 external audit and internal governance requirements of the reserves and resources estimation process. An independent audit of Beach’s reserves at 30 June 2021 was conducted by RISC Advisory Pty Ltd (RISC). In RISC’s opinion the YEJ21 reserves estimates are reasonable and have been prepared in accordance with the definitions and guidelines contained within the SPE-PRMS and generally accepted petroleum engineering and evaluation principles. The audit encompassed 52% of 2P reserves and included 69% of developed reserves and 38% of undeveloped reserves. Contingent resources have not been audited. 36 Beach Energy Limited Annual Report 2021 Kupe, Taranaki Basin, New Zealand 37 Sustainability Focused on Sustainability. The role of Gas As a significant producer of natural gas, Beach has an important role to play in a low carbon future, as natural gas is widely recognised for its part in reducing global emissions. Natural gas produces half the greenhouse gas emissions of coal when used to generate electricity.1 The International Energy Agency’s (IEA) Sustainable Development Scenario, under which global temperature growth is limited to well below 2 degrees, highlights the role of coal-to-gas switching. It states coal-to-gas switching is essential to the US’ decarbonisation providing almost a quarter of all emission reductions required.3 In the United Kingdom, coal-to-gas switching has contributed to a drop of 50 per cent in the emissions intensity of power generation since 2010.4 This has supported a drop in the UK’s total emissions of 32 per cent since 2008 and more than 50 per cent since 1990, overachieving on targets already at the leading edge of developed nations. In an Australian context, the development of more natural gas supplies is also seen as critical in reducing Australia’s emissions footprint. The Integrated System Plan (ISP), which models electricity generation over the next 20 years in the National Electricity Market (NEM), was updated in August 2020 by AEMO. The ISP predicts higher levels of gas fired power generation in 2041–42 relative to 2021–22 levels in all modelled scenarios, including the most ambitious ‘step change’ scenario, which would see most coal fired generation closed over this timeframe to achieve a 90% reduction in carbon emissions from power generation by 2041–42. Under this step change scenario, gas-fired generation increases 33% through to 2041–42, enabling renewables generation to increase by 285%. AEMO 2020 Integrated System Plan – Step Change Scenario 2021–22 % Share 2041–42 % Share % Change 61.2 1.5 7.8 0.4 29.1 2.2 1.5 5.1 9.7 81.4 –95 33 –9 3,442 285 Coal Gas Hydro Storage Renewables FY21 Sustainability Report The Beach Energy FY21 Sustainability Report will be released on 18 August 2021. To read this year’s report visit beachenergy.com.au/sustainability (1, 2, 3, 4). International Energy Agency, The Role of Gas in Today’s Energy Transitions, 2019 38 Sustainably delivering energy for Communities Regardless of the critical role natural gas has to play in the future energy mix, Beach recognises that climate change is one of the global challenges of this century and, as a member of the energy industry, it has a role to play in managing carbon emissions. As such, Beach is committed to integrating low emissions technologies in our operations and identifying opportunities for carbon emission reduction, where economically practicable. In addition, Beach is committed to playing a role in helping Australia and New Zealand meet their commitments under the Paris Agreement by: • Pursuing growth of natural gas – the transition fuel • Helping to meet the demand increase globally • Aligning with Australia’s energy ambitions • Modelling against various climate and pricing scenarios • Being part of an industry driven effort to lower absolute emissions – including emissions intensity Beach is focused on taking practical steps to reduce emissions from its operations, and in FY20, we announced our 25 by 25 initiative which aims to reduce emissions by 25 per cent by FY25 against FY18 levels. In FY21, we established a new Sustainability division of the business, to identify and ensure delivery of key emissions reductions initiatives. Beach also made significant progress on 25 by 25 in FY21, delivering the first projects which result in the reduction of flaring at both our key gas processing facilities in Victoria. Beach is also a participant, along with operator Santos, in the proposed Moomba Carbon Capture and Storage Project, which aims to safely and permanently store 1.7 million tonnes of carbon dioxide (CO2) per year. 800 600 400 200 e 2 O C t K ~12% On Track FY18 FY21 FY25 Subject to final National Greenhouse Emissions Reporting Scheme (NGERs) numbers. Does not include emissions from the acquired Senex Cooper Basin assets and fuel data for Katnook. 25BY 25 Progressing 25 by 25 Mercury Removal Facility Installation of mercury removal facilities into the Mol Sieve Regen Gas Circuit at Otway Gas Plant has resulted in Beach reducing its anticipated CO2 emissions by around 12,000 tonnes over the next 12 years. 12,000t Anticipated CO2 emission reduction over the next 12 years BassGas Start Up Procedure Change to plant operating parameters for restart using existing infrastructure resulting in reduced need for flaring and estimated reduction of 2,500 tonnes of CO2 per year. 2,500t Estimated reduction of CO2 per year Our Safest Year on Record At Beach, safety takes priority in everything we do. In FY21, Beach recorded its safest year on record, with a Total Recordable Injury Frequency Rate (TRIFR) of 2.1. This was a 40 per cent improvement from FY20. Beach also passed the significant milestone of three-million hours without a Lost Time Injury. Safety initiatives in FY21 that contributed to this result include: • Rollout of a new Operations Excellence Management System (OEMS) which sets out a framework for all of Beach’s policies and procedures • Delivery of a new Safety Strategy for the Cooper Basin. This initiative was a finalist in the 2021 Australian Petroleum Production and Exploration Association (APPEA) Awards. 39 Beach Energy Limited Annual Report 2021 Board of Directors Glenn Davis Independent Non-Executive Chairman LLB, BEc, FAICD Matthew (Matt) Kay Managing Director & Chief Executive Officer BEc, MBA, FCPA, GAICD Colin Beckett AO Independent Non-Executive Deputy Chairman Mr Davis has practiced as a solicitor in corporate and risk throughout Australia for over 30 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. 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 Kay joined Beach in May 2016 as Chief Executive Officer and was appointed to the Board as Managing Director in February 2019. In November 2018, he was elected to the Australian Petroleum Production & Exploration Association (APPEA) Board. Mr Kay brings 28 years of experience in the Oil and Gas industry to Beach. Before joining Beach, he served as Executive General Manager, Strategy and Commercial at Oil Search, a position he held for two years. In that role he was a member of the Executive team and led the strategy, commercial, supply chain, economics, marketing, M&A and legal functions. Prior to Oil Search, Mr Kay spent 12 years with Woodside Energy in various leadership roles, including Vice President of Corporate Development, General Manager of Production Planning and General Manager of Commercial for Middle East and Africa. In these roles Mr Kay developed extensive leadership skills across LNG, pipeline gas and oil joint ventures, and developments in Australia and internationally. 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). Mr Beckett’s special responsibilities include chairmanship of the Remuneration and Nomination Committee and membership of the Risk, Corporate Governance and Sustainability Committee. He was appointed to the Board on 2 April 2015, last having been re-elected to the Board on 26 November 2019. 40 Philip Bainbridge Independent Non-Executive Director BSc (Hons) Mechanical Engineering, MAICD 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 has 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. He is currently a member of PNG Sustainable Development Program, a company limited by guarantee and the non-executive chairman of the Global Institute of Carbon Capture and Storage. He was formerly the non-executive chairman of Sino Gas and Energy Holdings until 2018 and a non-executive director of Drillsearch Energy Limited from 2013 to 2016. Mr Bainbridge’s special responsibilities include membership of the Risk, Corporate Governance and Sustainability Committee and the Audit Committee. He was appointed by the Board on 1 March 2016, last having been elected to the Board on 26 November 2019. Joycelyn Morton Independent Non-Executive Director BEc, FCA, FCPA, FIPA, FCIS, FAICD Ryan Stokes AO Non-Executive Director BComm FAIM Ms Morton has extensive experience in finance and taxation having begun her career with Coopers & Lybrand (now PwC), followed by senior management roles with Woolworths Limited and global leadership roles in Australia and internationally within the Shell Group of companies. Ms Morton was National President of both CPA Australia and Professions Australia, has served on many committees and councils in the private, government and not-for-profit sectors and held international advisory positions. She holds a Bachelor of Economics degree from the University of Sydney. Her other current ASX listed board positions are Argo Investments Limited, Argo Global Listed Infrastructure Limited and Felix Group Holdings Limited. She is also a non-executive director of ASC Pty Ltd and, as of 30 June 2021, concluded nine years with Snowy Hydro Limited – both government owned corporations. She has valuable board experience across a range of industries, including previous roles as a non-executive director and Chair of both Thorn Group Limited and Noni B Limited and a non-executive director of Crane Group Limited, Count Financial Limited and InvoCare Limited. Ms Morton’s special responsibilities include membership of the Audit Committee. She was appointed a non-executive director of Beach Energy Limited on 23 February 2018. Mr Stokes is the Managing Director and Chief Executive Officer of Seven Group Holdings Limited (SGH). SGH is a listed diverse investment company involved in Industrial Services, Media, and Energy. SGH interests include 30.02% of Beach Energy, WesTrac, Coates Hire and 41% of Seven West Media Limited. Mr Stokes is Chairman of Boral Limited, Chairman of Coates Hire and a director of WesTrac and Seven West Media. Mr Stokes is Chief Executive Officer of Australian Capital Equity Pty Limited (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. He is also a member of the International Olympic Committee Education Commission. His previous roles include Chairman of the National Library of Australia, member of the Prime Ministerial Advisory Council on Veterans’ Mental Health, Founding Chair Headspace, Youth Mental Health Foundation. Mr Stokes is a member of the Remuneration and Nomination Committee. He was appointed by the Board on 20 July 2016, last having been re-elected to the Board on 23 November 2018. Margaret Helen Hall Alternate director for Ryan Stokes Non-Executive Director B.Eng (Met) Hons, MIEAust, GAICD, SPE Ms Hall was appointed alternate director for Mr Stokes on 3 May 2021. Biographical details regarding Ms Hall are set out within the Directors Report on page 57. 41 Beach Energy Limited Annual Report 2021 Board of Directors Richard Richards Non-Executive Director BComs/Law (Hons), LLM, MAppFin, CA, Admitted Solicitor Mr Richards is currently Chief Financial Officer of Seven Group Holdings Limited (SGH) (since October 2013). He is responsible for Finance across the diversified conglomerate (equipment manufacture, sales and service, equipment hire, investments, property, media and oil and gas). Mr Richards is a member of the Board of Directors of Boral Limited, WesTrac Pty Limited and SGH Energy Pty Limited, is a Director and Chair of the Audit and Risk Committee of Coates Hire Pty Limited, a Director and member of KU Children Services (NFP) and a member of the Marcia Burgess Foundation Committee (DGR). He has held senior finance roles with Downer EDI, the Lowy Family Group and Qantas. 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 as a member of the Risk, Corporate Governance & Sustainability Committee. He was appointed to the Board on 4 February 2017 and was last re-elected to the Board on 25 November 2020. 42 Dr Peter Moore Independent Non-Executive Director PhD, BSc (Hons), MBA, GAICD Sally-Anne Layman Independent Non-Executive Director B Eng (Mining) Hon, B Com, CPA, MAICD 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, was appointed to the Board in February 2019 and formally elected to the Board on 26 November 2019. 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 Risk, Corporate Governance and Sustainability Committee and membership of the Remuneration and Nomination Committee. Dr Moore was appointed by the Board on 1 July 2017 and last re-elected to the Board on 26 November 2019. Full Financial Report Directors’ Report Auditor’s Independence Declaration 2021 Remuneration in Brief (Unaudited) Remuneration Report (Audited) Directors’ Declaration Financial Statements 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 Expenses Employee benefits Taxation Earnings per share (EPS) Inventories Property, plant and equipment (PPE) Petroleum Assets Exploration and evaluation assets Intangible assets Interests in joint operations Provisions Leases Commitments for expenditure 3. 4. 5. 6. Capital employed 7. 8. 9. 10. 11. 12. 13. 14. 15. Financial and risk management 16. 17. 18. Equity and group structure Contributed equity 19. 20. Reserves Dividends 21. Subsidiaries 22. Deed of cross guarantee 23. Parent entity financial information 24. Related party disclosures 25. 26. Acquisitions and disposals Other information 27. Contingent liabilities 28. Remuneration of auditors Subsequent events 29. Finances and borrowings Cash flow reconciliation Financial risk management Independent Auditor’s Report Glossary Schedule of Tenements Shareholder information Corporate directory 125 130 132 137 BC 44 59 60 62 79 80 80 81 82 83 84 84 87 87 89 90 91 93 96 97 97 97 98 101 102 102 104 106 108 109 109 110 111 115 115 116 116 117 118 120 121 121 123 123 124 124 43 Beach Energy Limited Annual Report 2021 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 2021. 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 2021 and up to the date of this report are: Surname Davis Beckett Bainbridge Hall Kay Layman Moore Morton Richards Stokes Other Names Glenn Stuart Colin David Philip James Margaret Helen Matthew Vincent Sally-Anne Georgina Peter Stanley Joycelyn Cheryl Richard Joseph Ryan Kerry Position Independent non-executive Chairman Independent non-executive Deputy Chairman Independent non-executive director Alternate non-executive director (1) Managing director Independent non-executive director Independent non-executive director Independent non-executive director Non-executive director Non-executive director (1) Appointed as an alternate director for Mr Stokes on 3 May 2021. 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 C D Beckett P J Bainbridge M V Kay S G Layman P S Moore J C Morton R J Richards (3) R K Stokes (3) M H Hall (3)(4) Shares 320,101 (2) 91,678 (1) 137,320 (2) 3,918,255 (1) 45,000 (2) 44,200 (2) 74,000 (1)(2) 388,053 (2) – 17,068 (2) Rights – – – 3,105,102 (1) – – – – – – (1) Held directly. (2) Held by entities in which a relevant interest is held. (3) Mr Stokes does not hold a relevant interest in Beach shares but he 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. He is Managing Director and Chief Executive Officer of SGH. Mr Richards was also nominated as a director by SGH. He is the Chief Financial Officer of SGH. Ms Hall is the chief executive officer of Seven Group Holdings Energy. (4) Ms Hall is an alternate director for Mr Stokes, appointed till no later than 3 May 2022 or until terminated in accordance with the Beach constitution. Details of the qualifications, experience, special responsibilities and meeting attendance of each of the directors are set out later in the Directors’ Report. 44 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 the highest 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 17 to 31. Financial results from FY21 are summarised below: – Group profit attributable to equity holders of Beach was $316.5 million (FY20 $499.1 million). – Sales revenue was down 8% from FY20 to $1,519.4 million due to lower volumes and unfavourable A$/US$ exchange rates, partly offset by favourable US dollar oil and liquids prices. – Cost of sales were down 8% from FY20 to $967.1 million, mainly as a result of lower tariff and toll charges, royalties, third party purchases and depreciation partly offset by inventory movements. – A net profit after tax of $316.5 million was reported reflecting lower sales and other revenue, higher impairment and exploration expense partly offset by lower cost of sales and related tax impacts. Key Results Operations Production Production (pro-forma) (1) Sales Capital expenditure Income Sales revenue Total revenue Cost of sales Gross profit Other income Net profit after tax (NPAT) Underlying NPAT (2) Dividends paid Dividends announced Basic EPS Underlying EPS (2) Cash flows Operating cash flow Investing cash flow Financial position Net assets Cash balance 2021 2020 Change MMboe MMboe MMboe $m $m $m $m $m $m $m $m cps cps cps cps $m $m $m $m 24.8 25.6 26.1 (671.3) 1,519.4 1,562.0 (967.1) 594.9 51.1 316.5 363.0 2.00 1.00 13.88 15.92 26.7 26.7 27.7 (863.0) 1,650.3 1,728.2 (1,056.7) 671.5 76.6 499.1 459.3 2.00 1.00 21.89 20.15 759.8 (757.8) 873.9 (899.2) 3,087.8 126.7 2,817.8 109.9 (7%) (4%) (6%) 22% (8%) (10%) 8% (11%) (33%) (37%) (21%) 0% 0% (37%) (21%) (13%) 16% 10% 15% Includes the impact of the acquisition of Senex Energy’s Cooper Basin assets and Mitsui’s Bass Basin assets, with an effective date 1 July 2020. (1) (2) 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 47 for a reconciliation of this information to the financial report. 45 Beach Energy Limited Annual Report 2021 Directors’ Report Revenue Sales revenue of $1,519.4 million in FY21 was $130.9 million or 8% lower than FY20, driven by lower production volumes, higher FX rates and lower third-party sales, partly offset by higher realised prices. Lower production volumes, largely from the Western Flank, decreased sales revenue by $106.8 million, unfavourable A$/US$ exchange rates in FY21 resulted in a reduction in revenue of $69.3 million and lower sales from third party product decreased revenue by $24.7 million. US dollar oil and liquids prices increased in FY21 resulting in an additional $65.5 million in revenue with the average realised liquid price increasing to US$57.56/boe, up from US$52.36/boe in FY20. Sales Revenue Comparison ($m) 1,800 1,600 1,400 1,200 1,000 800 600 400 200 0 1,650.3 65.5 Oil and liquids prices US$/boe FY20 $52.36 FY21 $57.56 4.4 (24.7) Third party sales Gas/ethane prices A$/GJ FY20 $7.29 FY21 $7.35 (69.3) FX rates A$/US$ FY20 $0.671 FY21 $0.747 (106.8) Volume/ mix 1,519.4 8% $130.9 million total decrease FY20 Average price A$59.66/boe FY21 Average price A$58.28/boe Gross Profit Gross profit for FY21 of $594.9 million (FY20 $671.5 million) was down 11%, driven by lower sales and other revenue and inventory movements, partly offset by lower total operating costs, depreciation and third party purchases. The decrease in cost of sales, down 8% from FY20 to $967.1 million, is due principally to lower total operating costs, primarily lower tariff and toll charges of $84.9 million including the favourable arbitral outcome regarding the allocation of carbon emissions under one of Beach’s long term gas sales agreements and royalties of $7.4 million as a result of lower sales revenue and lower Cooper Basin volumes. Third party purchases were lower reflecting less crude shipments with depreciation also lower due to reduced production volumes. These are partly offset by inventory movements of $42.6 million driven by lower Cooper Basin volumes and costs. Gross Profit Comparison ($m) 80.9 26.7 24.6 (42.6) 671.5 Depreciation Third party purchases Inventory Total Operating Costs (166.2) Sales and other revenue Cost of Sales $89.6 million 11% $76.6 million total decrease FY20 594.9 FY21 900 800 700 600 500 400 300 200 100 0 46 Net Profit Result Other income of $51.1 million, is $25.5 million lower than FY20, due to lower joint venture lease recoveries of $5.7 million and the prior period including gains on sale of joint operations of $8.9 million and cessation of overseas operations of $8.7 million. Other expenses of $203.7 million were $160.2 million higher from FY20 with the impairment of the SA Otway $117.0 million, exploration and evaluation expenditure expensed during FY21 of $56.7 million, relating to the IronBark exploration well drilled in FY21 and relinquishment of exploration areas of interest in FY21, and foreign exchange losses realised of $8.9 million. The reported net profit after income tax of $316.5 million is $182.6 million lower than FY20, due to the lower gross profits driven by lower volumes, higher other expenses resulting from impairment of assets during the period, partially offset by lower income tax corresponding with lower profits. By adjusting the FY21 profit to exclude asset impairment and an acquisition related liability reversal, Beach’s underlying net profit after tax is $363.0 million. Comparison of underlying profit Net profit after tax Adjusted for: Gain on asset disposals Gain on reversal of acquired liabilities Impairment of assets Tax impact of above changes Underlying net profit after tax(1) FY21 $ million FY20 $ million Movement from PCP $ million 316.5 499.1 (182.6) -37% – (35.4) 117.0 (35.1) (17.6) (37.8) 1.6 14.0 363.0 459.3 17.6 2.4 115.4 (49.2) (96.3) -21% (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 Notes 2(b) and 3(b) to the financial statements. Underlying Net Profit After Tax Comparison ($m) 550 500 450 400 350 300 250 200 150 100 50 0 459.3 22.1 Tax 8.5 Net financing costs (50.3) Other expenses and income (76.6) Gross profit 21% $96.3 million total decrease FY20 363.0 FY21 47 Beach Energy Limited Annual Report 2021 Directors’ Report Financial Position Assets Total assets increased by $466.9 million to $4,679.2 million during the period with cash balances increased by $16.8 million to $126.7 million, primarily due to: – Cash inflow from operations of $759.8 million, – Cash inflow from financing activities of $21.0 million, offset by, – Cash outflow from investing activities of $757.8 million, and – Unfavourable foreign exchange impact of $6.2 million. Receivables increased by $139.2 million due to higher sales accruals driven by higher prices at the end of the period and receivables recognised following the favourable arbitral outcome regarding the allocation of carbon emissions under one of Beach’s long term gas sales agreements and the acquisition of Mitsui’s interest in the BassGas assets. Inventories decreased by $7.5 million. Other current assets increased by $14.6 million, primarily driven by the recognition of Victoria Otway sublease receivable. Fixed assets, petroleum and exploration assets increased by $316.5 million. Capital expenditure of $643.4 million, acquisitions of $166.7 million, increases for restoration of $57.5 million and the capitalisation of depreciation of lease assets under AASB 16 Leases of $27.3 million. This is partly offset by depreciation and amortisation of $407.3 million, impairment of assets of $117.0 million and exploration and evaluation expenditure expensed during the period of $56.7 million. Deferred tax assets decreased by $33.6 million. Other non-current assets increased $19.4 million due to higher prepayments. Lease assets recognised under AASB 16 Leases increased by $13.5 million with new contracts offsetting the depreciation during the period. Liabilities Total liabilities increased by $196.9 million to $1,591.4 million, due to an increase in provisions of $152.6 million mainly relating to restoration on the acquisitions of Senex owned assets and Mitsui’s share of BassGas, as well as for wells drilled in FY21, increase in debt drawn of $115 million and lease liabilities of $40.9 million partially offset by a decrease in current tax liability of $82.5 million and contract liabilities of $32.3 million. Equity Total equity increased by $270.0 million, primarily due to net profit after tax of $316.5 million, partly offset by dividends paid during the period of $45.6 million. Dividends During the financial year, the Company paid a FY20 fully franked final dividend of 1.0 cent per share as well as an interim FY21 fully franked dividend of 1.0 cent per share. The Company will also pay a FY21 fully franked final dividend of [1.0] cent per share from the profit distribution reserve. 48 State of affairs A review of operations of Beach Energy during the financial year on pages 17 to 31 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. Funding and capital management As at 30 June 2021, Beach held cash and cash equivalents of $127 million. Beach currently has a Senior Secured Debt Facility in place for $525 million, comprised of a $450 million revolving debt facility (Facility C) and a $75 million Letter of Credit facility (Facility D), both of which have a maturity date of November 2022. As at 30 June 2021 $175 million of Facility C was drawn with $275 million remaining undrawn, with $73 million of Facility D being utilised predominantly by way of bank guarantees. Material Business Risks Beach recognises that the management of risk is a critical component in Beach achieving its purpose of delivering sustainable growth in shareholder value. 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. 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, health, safety and environmental risks, community and social licence risks and legal risks. These may be further categorised as strategic risks, operational risks, commercial risks, regulatory risks, reputational risks and financial risks. A description of the nature of the risk 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 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 have been very volatile. A sustained period of low or declining crude oil prices 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. This process is a significant development in Beach’s continuing focus on reducing capital and operating expenditure and improving business efficiency. Declines in the price of oil and continuing price volatility may also lead to revisions of the medium and longer term price assumptions for oil from future production, which, in turn, may lead to a revision of the carrying value of some of Beach’s assets. 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. Foreign exchange and hedging risk Beach’s financial report is presented in Australian dollars. Beach converts funds to foreign currencies as its payment obligations in those jurisdictions where the Australian dollar is not an accepted currency become due. Certain of Beach’s costs will be incurred in currencies other than Australian dollars, including the US dollar and the New Zealand dollar. Accordingly, Beach is subject to fluctuations in the rates of currency exchange between these currencies. The Company may use derivative financial instruments such as foreign exchange contracts, commodity contracts and interest rate swaps to hedge certain risk exposures, including commodity price fluctuations through the sale of petroleum productions and other oil-linked contracts. Ability to access funding The oil and gas business involves significant capital expenditure in relation to exploration and development, production, processing and transportation. Beach relies on cash flows from operating activities and bank borrowings and offerings of debt or equity securities to finance capital expenditure. If cash flows decrease or Beach is unable to access necessary financing, this may result in postponement of or reduction in planned capital expenditure, relinquishment of rights in relation to assets, or an inability to take advantage of opportunities or otherwise respond to market conditions. Any of these outcomes could have a material adverse effect on Beach’s ability to expand its business and/or maintain operations at current levels, which in turn could have a material adverse effect on Beach’s business, financial condition and operations. Beach has 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 to support this policy. Beach has a treasury function and clear delegations and reporting obligations. The annual capital and operating budgeting processes approved by the Board ensure appropriate allocation of resources. 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, or 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), could have an adverse effect on the reputation and/or the financial performance of Beach. 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. 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 producing the reserves. Estimates that are valid at a certain point in time may alter significantly or become uncertain when new reservoir information becomes available through additional drilling or subsurface technical analysis over the life of the field. 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 and Society of Petroleum Evaluation Engineers (SPE-PRMS). These estimates are subject to periodic independent external review or audit. 49 Beach Energy Limited Annual Report 2021 Directors’ Report 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. Individual projects being undertaken by Beach may also be affected by any restrictions relating to the COVID-19 pandemic. Beach utilises well-established prospect evaluation and ranking methodology to manage exploration and development risks. Production risks Any oil or gas project, including off-shore activity, may be exposed to production decrease or stoppage, which may be the result of facility shut-downs, mechanical or technical failure, 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 such disruptions as a result of the restrictions on the movement and supply of personnel and products in response to the COVID-19 pandemic. A significant failure to meet production targets could compromise the 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 Signals Directorate (ASD) Essential 8 Maturity Framework that include application allow listing, system hardening and retiring of legacy systems. In addition, we have expanded validation of existing controls through regular penetration testing, phishing simulations and cyber exercises. 50 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. 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 and Native Title 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. Beach’s standard operating procedures and stakeholder engagement processes are used to manage land access, cultural heritage and native title risks. Health, safety and environmental risks Climate change 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 a health, safety and environment 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 and the impact of COVID-19 (for example, due to a deterioration in an insurers ability to honour claims), could adversely affect Beach’s business, financial position and operational results. Beach’s ability to mitigate these risks and effectively respond to health and safety incidents may be also impaired by restrictions on the movement of products and personnel relating to the COVID-19 pandemic. 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. 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 are incorporated into Company policy, strategy and risk management processes and practices. The Company actively monitors current and potential areas of climate change risk and takes actions to prevent and/or mitigate any 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. 51 Beach Energy Limited Annual Report 2021 Directors’ Report 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 operations of petroleum activities as appropriate. For licences operated by other companies, this is achieved by monitoring 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 1.0 cent per share on 30 September 2021. The record date for entitlement to this dividend is 31 August 2021. The financial impact of this dividend, amounting to $22.8 million has not been recognised in the Financial Statements for the year ended 30 June 2021 and will be recognised in subsequent Financial Statements. The details in relation to dividends paid during the reporting period are set out below: Dividend FY20 Final FY21 Interim Record Date 31 August 2020 26 February 2021 Date of payment 30 September 2020 31 March 2021 Cents per share Total Dividends 1.0 1.0 $22.8 million $22.8 million For Australian income tax purposes, all dividends were fully franked and were not sourced from foreign income. Share options and rights Beach does not have any options on issue at the end of financial year and has not issued any during FY21. 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 On 25 November 2020, Beach issued 263,199 Short Term Incentive (STI) unlisted performance rights under the Executive Incentive Plan (EIP). These performance rights are exercisable for nil consideration and are not exercisable before 1 July 2021 and 1 July 2022. On 14 December 2020, Beach issued 2,360,550 Long Term Incentive (LTI) unlisted performance rights under the EIP. On 31 May 2021, Beach issued a further 311,722 LTI unlisted performance rights under the EIP. 28,619 performance rights, which expire on 30 November 2024, are exercisable for nil consideration and are not exercisable before 1 December 2022. 2,643,653 performance rights, which expire on 30 November 2025, are exercisable for nil consideration and are not exercisable before 1 December 2023. 52 Rights 2017 LTI unlisted rights Balance at beginning of financial year Issued during the financial year Vested/ exercised during the financial year Expired/ lapsed during the financial year Issued 1 December 2017 and 9 April 2018 2,283,944 2017 STI unlisted rights Issued 6 December 2018 2018 LTI unlisted rights 206,847 Issued 14 December 2018 and 19 December 2019 2,192,835 2018 STI unlisted rights Issued 19 December 2019 2019 LTI unlisted rights 637,259 – – – – Issued 19 December 2019 and 14 December 2020 1,602,015 28,619 2019 STI unlisted rights Issued 25 November 2020 2020 LTI unlisted rights Issued 14 December 2020 and 31 May 2021 – – 263,199 2,643,653 (1,069,650) (206,847) – – – (550,388) 1,642,447 (318,632) (43,518) 275,109 – – – (406,522) 1,224,112 (49,534) 213,665 (331,421) 2,312,232 Balance at end of financial year 1,214,294 – Total 6,922,900 2,935,471 (1,595,129) (1,381,383) 6,881,859 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. 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 Total (1) 3-year restriction period end on the first practicable date after 30 June 2022. (2) 3-year restriction period end on the first practicable date after 30 June 2023. Balance at beginning of financial year Issued during the financial year Vested during the financial year Expired/ lapsed during the financial year Balance at end of financial year 514,235 – – 514,235 821,546 821,546 – – – (11,732) 502,503 (21,569) 799,977 (33,301) 1,302,480 53 Beach Energy Limited Annual Report 2021 Directors’ Report 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: Current and former listed company directorships in the last 3 years Nil. Responsibilities His special responsibilities include chairmanship of the Remuneration and Nomination Committee and membership of the Risk, Corporate Governance and Sustainability 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. 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 has 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. He is currently a member of the PNG Sustainable Development Program, a company limited by guarantee and the non-executive chairman of the Global Institute of Carbon Capture and Storage. Current and former listed company directorships in the last 3 years Mr Bainbridge was formerly the non-executive chairman of Sino Gas and Energy Holdings (from 2014 until 2018). Responsibilities His special responsibilities include membership of the Risk, Corporate Governance and Sustainability Committee. Date of appointment Mr Bainbridge was appointed to the Board on 1 March 2016 and was last re-elected to the Board on 26 November 2019. Glenn Stuart Davis Independent non-executive Chairman – LLB, BEc, FAICD Experience and expertise Mr Davis has practiced as a solicitor in corporate and risk throughout Australia for over 30 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 a former director of ASX listed company Auteco Minerals (previously called Monax Mining Limited) (from 2004 to November 2018). 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. 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). 54 Matthew Vincent Kay Managing director & Chief executive officer – BEc, MBA, FCPA, GAICD Experience and expertise Mr Kay joined Beach in May 2016 as Chief Executive Officer. Mr Kay has circa 30 years’ experience in energy and resources and prior to joining Beach, served as Executive General Manager, Strategy and Commercial at Oil Search, a position he held for two years. In that role he was a member of the executive team and led the strategy, commercial, supply chain, economics, marketing, M&A and legal functions. Prior to Oil Search, Mr Kay spent 12 years with Woodside Energy in various leadership roles, including Vice President of Corporate Development, General Manager of Production Planning leading over 80 operations professionals, and General Manager of Commercial for Middle East and Africa. In these roles Mr Kay developed extensive leadership skills across LNG, pipeline gas and oil joint ventures, and developments in Australia and internationally. Current and former listed company directorships in the last 3 years Nil. Responsibilities Managing Director & Chief Executive Officer. Date of appointment Mr Kay was appointed managing director of Beach Energy Limited on 25 February 2019 and elected to the Board on 26 November 2019. Sally-Anne Layman Independent non-executive director – B Eng (Mining) Hon, B Com, CPA, MAICD 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. 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) and Gascoyne Resources Ltd (from June 2017 until May 2019). Responsibilities Her special responsibilities include Chair of the Audit Committee. Date of appointment Ms Layman was appointed to the Board on 25 February 2019 and elected to the Board on 26 November 2019. 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) and was previously a non-executive director of Central Petroleum Ltd (from 2014 to November 2018). Responsibilities His special responsibilities include Chairmanship of the Risk, Corporate Governance and Sustainability Committee and membership of the Remuneration and Nomination Committee. Date of appointment Dr Moore was appointed by the Board on 1 July 2017 and then elected to the Board on 26 November 2019. 55 Beach Energy Limited Annual Report 2021 Directors’ Report Joycelyn Cheryl Morton Independent non-executive director – BEc, FCA, FCPA, FIPA, FCIS, FAICD Experience and expertise Ms Morton has extensive experience in finance and taxation having begun her career with Coopers & Lybrand (now PwC), followed by senior management roles with Woolworths Limited and global leadership roles in Australia and internationally within the Shell Group of companies. Ms Morton was National President of both CPA Australia and Professions Australia, has served on many committees and councils in the private, government and not-for-profit sectors and held international advisory positions. She holds a Bachelor of Economics degree from the University of Sydney. She is also a non-executive director of ASC Pty Ltd (since 2017) – a government owned corporation. In addition, Ms Morton has valuable board experience across a range of industries, including previous roles as a non-executive director and Chair of both Thorn Group Limited (from 2011 to 2018) and Noni B Limited (from May 2009 to February 2015) and a non-executive director of Crane Group Limited (from October 2010 to April 2011), Count Financial Limited (from 2006 to 2011) and InvoCare Limited (from August 2015 to May 2018). Current and former listed company directorships in the last 3 years Ms Morton is currently a non-executive director of Argo Investments Limited (since 2012), Argo Global Listed Infrastructure Limited (since March 2015) and Felix Group Holdings Limited (since July 2021). She previously was non-executive director of Snowy Hydro (until June 2021) and non-executive director and Chair of Thorn Group Limited (from 2011 to 2018) and non-executive director of InvoCare Limited (from 2015 to 2018). Responsibilities Her special responsibilities include membership of the Audit Committee. Date of appointment Ms Morton was appointed a non-executive director of Beach Energy Limited on 21 February 2018 and then elected to the Board on 23 November 2018. Richard Joseph Richards Non-executive director – BComs/Law (Hons), LLM, MAppFin, CA, Admitted Solicitor Experience and expertise Mr Richards is currently Chief Financial Officer of Seven Group Holdings Limited (SGH) (since October 2013). He is responsible for Finance across the diversified conglomerate (equipment manufacture, sales and service, equipment hire, investments, property, media and oil and gas). Mr Richards is a member of the Board of Directors of WesTrac Pty Limited, SGH Energy Pty Limited, Boral Limited (from August 2021), is a 56 Director and Chair of the Audit and Risk Committee of Coates Hire Pty Limited, a former Director and Chair of the Audit and Risk Committee of KU Children Services (NFP) and a member of the Marcia Burgess Foundation Committee (DGR). He has held senior finance roles with Downer EDI, the Lowy Family Group and Qantas. 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. Current and former listed company directorships in the last 3 years Boral Limited during October 2020 and was reappointed in August 2021. Responsibilities His special responsibilities include membership of the Audit Committee and a member of the Risk, Corporate Governance & 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 – BComm, FAIM Experience and expertise Mr Stokes is the Managing Director and Chief Executive Officer of Seven Group Holdings Limited (SGH). SGH is a listed diverse investment company involved in Industrial Services, Media and Energy. SGH interests include 30.02% of Beach Energy, WesTrac Pty Limited, Coates Hire, 69.9% of Boral Limited and 41% of Seven West Media Limited. Mr Stokes is Chairman of Boral Limited, Chairman of Coates Hire and a director of WesTrac Pty Limited and Seven West Media. Mr Stokes is Chief Executive Officer of Australian Capital Equity Pty Limited (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. He is also a member of the International Olympic Committee Education Commission. His previous roles include Chairman of the National Library of Australia, member of the Prime Ministerial Advisory Council on Veterans’ Mental Health, Founding Chair Headspace, Youth Mental Health Foundation. Current and former listed company directorships in the last 3 years Mr Stokes is an executive director of Seven Group Holdings (since 2010) and a non-executive director of Seven West Media (since 2012) and Boral Limited (since Sep 2020). Responsibilities His special responsibilities include membership of the Remuneration and Nomination Committee. Date of appointment Mr Stokes was appointed to the Board on 20 July 2016 and then elected to the Board on 23 November 2018. Margaret Helen Hall – alternate director Non-executive director – B.Eng (Met) Hons, MIEAust, GAICD, SPE Alternate for Mr Ryan Stokes 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 28 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 Ms Hall has had no listed company directorships in the last 3 years. Date of appointment Ms Hall was appointed alternate director for Mr Stokes on 3 May 2021, pursuant to the terms of the Beach constitution. Ms Hall’s appointment will continue for a period of one year or until terminated in accordance with Beach’s constitution. There are no directors of Beach who held office during the financial year and are no longer on the Board. 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 15 15 15 15 15 15 15 15 15 1 15 15 15 15 14 15 14 (3) 15 14 (2) 1 (2) – – – – 6 – 6 6 – – – – – – 6 – 6 6 – – 6 6 – – – 6 – – 6 – 6 6 – – – 5 – – 6 – – 5 5 – – 5 – 2 – – Name G S Davis C D Beckett P J Bainbridge M V Kay S G Layman P S Moore J C Morton R J Richards R K Stokes M H Hall (1) Number of Meetings held during the time that the director was appointed to the Board or committee. (2) Ms Hall was only required to attend one meeting during the year as an alternate director for Mr Stokes. (3) Ms Morton was an apology due to Beach information technology issues. Board Committees Chairmanship and current membership of each of the board committees at the date of this report are as follows: Committee Audit Risk, Corporate Governance & Sustainability Remuneration and Nomination Chairman S G Layman P S Moore (1) C D Beckett Members J C Morton, R J Richards P J Bainbridge, C D Beckett, R J Richards (2) G S Davis, R K Stokes, P S Moore (1) Mr Bainbridge ceased as committee chair on 25 June 2021 and Dr Moore commenced as committee chair. (2) Mr Richards commenced as a committee member on 25 March 2021. – 5 5 – – 5 – 2 – – 57 Beach Energy Limited Annual Report 2021 Directors’ Report Indemnity of Directors and Officers 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. Company Secretary Daniel Murnane Company Secretary – BA/LLB Mr Murnane joined Beach in May 2018 as Senior Legal Counsel and was appointed to Company Secretary on 2 March 2020. He has more than 16 years’ experience, including over 12 years advising resources companies. Mr Murnane has worked as a senior associate in private legal practice predominately for energy companies on mergers and acquisitions, major projects, capital raisings and commercial disputes. In addition, Mr Murnane has held various in-house roles spanning legal and corporate governance environments, including with a NYSE listed oil and gas company. Mr Murnane is qualified as a solicitor in New South Wales and Papua New Guinea and holds a Bachelor of Arts and a Bachelor of Laws. 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 28 to the financial statements. Rounding off of amounts 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. 58 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 The acquisition by Beach of Mitsui’s 35.0% interest in the BassGas Project (comprising the onshore Lang Gas Plant and Yolla gas field), as well as its 40.0% interest in the Trefoil development project and surrounding retention lease completed on 31 July 2021 with an adjustment made to the acquisition price based on cash flows from the effective date of 1 July 2020 to the completion date. The Group has received a favourable arbitral outcome in relation to a contractual dispute under one of its long term gas sales agreements in New Zealand regarding the allocation of carbon emission obligations between the parties. A one-off cash payment of circa NZ$42m (plus interest) will be received in reimbursement of costs incurred to satisfy the emission obligations under the gas sales agreement during the period of the dispute. The details of the dispute are confidential. Other than the matters described above, there has not arisen in the interval between 30 June 2021 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, 16 August 2021 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 2021, 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; and b. No contraventions of 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 Anthony Jones Partner 16 August 2021 A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 59 Beach Energy Limited Annual Report 2021 2021 Remuneration in Brief (Unaudited) Remuneration to executive key management personnel in FY21 Consistent with FY20 remuneration outcomes, Board and management have sought to ensure FY21 remuneration takes into account broader economic conditions which have impacted Beach whilst 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. FY21 remuneration outcomes at a glance Fixed Remuneration NO INCREASES IN FY21 BENCHMARK INCREASE FOR ONE SENIOR EXECUTIVE Short Term Incentive (STI) NO STI AWARDED Long Term Incentive (LTI) LTI VESTED Non-executive directors BASE FEES UNCHANGED Total fixed remuneration (TFR) increased for one senior executive according to industry benchmarks. No other TFR increases were applied in FY21 (including KMP). Senior executives (excluding new starters) were subject to a 10% reduction in base remuneration for the period from 1 July 2020 for a period of 6 months in recognition of the COVID-19 impact on the global economy. Although one of the two hurdle measures have been met (return on capital), the Board has exercised its discretion and determined that no FY21 STI will be awarded. The 2017 and 2018 STI performance rights converted automatically to shares on the retention condition being met on 1 July 2020. The 2017 LTI performance rights fully vested following achievement of the performance conditions on 30 November 2020. Fees payable to non-executive directors was unchanged during the financial year, save that non-executive directors were subject to a 10% reduction in base remuneration for the period from 1 July 2020 for a period of 6 months in recognition of the COVID-19 impact on the global economy. 2020 AGM Remuneration Report 98.9% ‘YES VOTE’ Beach received more than 98% of ‘yes’ votes on a poll to adopt its Remuneration Report for the 2020 financial year. No specific feedback on Beach’s remuneration practices was received at the 2020 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 senior executives. 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. 60 The following table is a summary of remuneration actually paid or payable to executive KMP for FY21. It is not audited. Table 1: Remuneration to executive key management personnel (unaudited) Name M V Kay Managing Director and Chief Executive Officer I Grant Chief Operating Officer M Engelbrecht Chief Financial Officer S Algar (2) Group Executive Exploration & Subsurface T Nador (2) Group Executive Development L Marshall Group Executive Corporate Strategy & Commercial Former KMP G J Barker (3) Group Executive Development J L Schrull (3) Group Executive Exploration & Appraisal Total TFR Salary $ Super $ STI cash bonus $ 1,177,864 25,000 601,054 25,000 545,954 25,000 220,500 12,187 165,864 8,750 439,703 25,000 277,307 16,250 303,684 3,731,930 16,250 153,437 – – – – – – – – – Other (1) $ – Total Cash $ 1,202,864 54,750 680,804 – 570,954 54,750 287,437 – 174,614 60,000 524,703 – – 293,557 319,934 169,500 4,054,867 (1) 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. (2) Mr Algar and Mr Nador both became KMP with effect from 23 February 2021 with their remuneration only shown for the period from that date until 30 June 2021. (3) Mr Barker and Mr Schrull both ceased to be KMP on 22 February 2021 although continued to be employed with no decision making rights until 18 July 2021 and 18 May 2021 respectively. 61 Beach Energy Limited Annual Report 2021 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 2021. 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 FY21 Name Executive KMP M V Kay M Engelbrecht I Grant T Nador L Marshall S Algar Non-executive Directors G S Davis P J Bainbridge C D Beckett P S Moore J C Morton R J Richards R K Stokes S G Layman M H Hall Former KMP G J Barker J Schrull Position Period as KMP during the year Managing Director & Chief Executive Officer (MD & CEO) Chief Financial Officer Chief Operating Officer Group Executive Development Group Executive Corporate Strategy and Commercial Group Executive Exploration and Subsurface All of FY21 All of FY21 20 July 2020 – 30 June 2021 23 February 2021 – 30 June 2021 All of FY21 23 February 2021 – 30 June 2021 Independent Chairman Non-executive Director Non-executive Director Non-executive Director Non-executive Director Non-executive Director Non-executive Director Non-executive Director Alternate Director All of FY21 All of FY21 All of FY21 All of FY21 All of FY21 All of FY21 All of FY21 All of FY21 3 May 2021 – 30 June 2021 Group Executive Development Group Executive Exploration and Appraisal 1 July 2020 – 22 February 2021 1 July 2020 – 22 February 2021 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 that purpose: – 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 has a process to track compliance with its no hedging policy. Beach’s Share Trading Policy is available at Beach’s website: www.beachenergy.com.au. 62 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 MD & 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. 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 MD & CEO about executive remuneration. The MD & 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 FY20 and FY21 are detailed in Table 8. Table 3: Shareholder wealth indicators FY17 – FY21 Total revenue Net profit/(loss) after tax Underlying net profit after tax Share price at year-end Dividends declared Reserves Production FY17 FY18 FY19 FY20 FY21 $665.7m $387.5m $161.7m 57.5 cents 2.00 cents 75 MMboe 10.6 MMboe $1,267.4m $198.8m $301.5m 175.5 cents 2.00 cents 313 MMboe 19.0 MMboe $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 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. 63 Beach Energy Limited Annual Report 2021 Remuneration Report (Audited) 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: 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. 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 MD & 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 FY20 and FY21. Table 4: Remuneration mix (1) Position MD & CEO 2021 2020 Other Executive KMP 2021 2020 Performance based remuneration Fixed Remuneration % STI % LTI % 34 34 51 51 33 33 23 23 33 33 26 26 Total ‘at risk’ % 66 66 49 49 (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. Fixed remuneration What is fixed remuneration? 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. How is fixed remuneration reviewed? 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 8 reports on the remuneration for KMP as required under the Corporations Act. Table 1 shows the actual realised cash remuneration that KMP received. 64 Short Term Incentive (STI) What is the STI? How does the STI link to Beach’s objectives? 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. 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 Reserves replacement All in cost/boe Personal safety Process safety Environment Individual KPIs Weighting 75% 15% 15% 15% 15% 5% 5% 5% 25% Refer to Table 6 for more information. 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: gender diversity targets; 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. 65 Beach Energy Limited Annual Report 2021 Remuneration Report (Audited) What is the value of the STI award that can be earned? Incentive payments are based on a percentage of a senior executive’s fixed remuneration. The MD & CEO can earn up to a maximum of 100% of his fixed remuneration. How are the performance conditions assessed? Is there a threshold level of performance or hurdle before an STI is paid? The value of the award that can be earned by other senior executives is up to a maximum of 45% 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 MD & CEO’ s recommendation. The Board assesses the achievement of the KPIs for the MD & 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 One year Relative Total Shareholder Return against the ASX 200 Energy Index (Index Return) for the Performance Period Return on capital (1) Green Red > = Index return < Index return > = 10% < 10% (1) Return on capital (ROC) is based on statutory NPAT/average total equity (being the average total equity at the beginning and end of the financial year). 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 October. 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: FY21 measures 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 Outcome Hurdle (16.9%) 10.7% 6.9% 10.0% Although one of the two hurdle measures have been met, the Board exercised its discretion and determined that no FY21 STI will be awarded. Whilst no STI will be payable, outcomes of the Company related performance conditions that make up a fixed percentage of the STI KPIs are provided in Table 6. 66 Table 6: Outcome of FY21 STI Company KPIs STI Measure Production Statutory NPAT Reserves replacement All in cost/boe Personal safety Process safety Link to Beach’s strategy Performance and score Production is fundamental to Beach’s earnings and profit. Beach’s full year production was 25.6 MMboe. Score – threshold not met. Statutory NPAT reflects Beach’s earning performance. Stretch performance is achieved through strong sales revenue and cost reduction. Replacing reserves is fundamental to Beach’s longer term financial sustainability. Maintaining a cost and efficiency focus in order to optimise our core production hubs and maintain financial strength are key strategic pillars. Beach’s key value is that ‘Safety takes precedence in everything we do’. Beach is focused on ensuring it and its contractors operate in a safe manner. Beach has included other safety and reliability measures in the annual Sustainability Report. The Sustainability Report is available on Beach’s website. In FY21 Beach delivered Statutory NPAT of $316.5 million. Score – threshold not met. Beach’s 2P reserves increased by 12.6 MMboe (excluding production and divestments) to 339 MMboe. Score – threshold not met. Beach’s all in cost/boe for FY21 was $9.97. Score – threshold not met. Beach achieved a total recordable injury frequency rate (TRIFR) of 2.2. Score – stretch met. Beach recorded one Loss of Primary Containment events during the year. Score – target met. Environment Beach strives to reduce the environmental impact of its activities. Beach recorded two loss of hydrocarbon events in FY21. Score – threshold met. STI performance rights issued in 2019 and 2020 to senior executives converted automatically to shares because they remained employed by the Company on 1 July 2021. A total of 386,613 shares were transferred. STI performance rights issued or in operation in FY21 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. 67 Beach Energy Limited Annual Report 2021 Remuneration Report (Audited) 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: – 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. How are the number of rights issued to senior executives calculated 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? 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. What is the performance condition? 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. 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? 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. 68 Table 7: Details of LTI equity awards issued, in operation or tested during the year Details Type of grant 2017, 2018, 2019 and 2020 Performance Rights Performance rights Calculation of grant limits for senior executives Max LTI is 100% of Total Fixed Remuneration (TFR) for MD & CEO Max LTI is 50% of TFR for other senior executives Grant date 2020 Performance Rights 14 Dec 2020/31 May 2021 2019 Performance Rights 19 Dec 2019/14 Dec 2020 2018 Performance Rights 14 Dec 2018/19 Dec 2019 2017 Performance Rights 1 Dec 2017/9 April 2018 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 2020 Performance Rights 1 Dec 2020 – 30 Nov 2023 2019 Performance Rights 1 Dec 2019 – 30 Nov 2022 2018 Performance Rights 1 Dec 2018 – 30 Nov 2021 2017 Performance Rights 1 Dec 2017 – 30 Nov 2020 Expiry/lapse Expiry date Performance rights lapse if vesting does not occur on testing of performance condition 2020 Performance Rights 30 Nov 2025 2019 Performance Rights 30 Nov 2024 2018 Performance Rights 30 Nov 2023 2017 Performance Rights 30 Nov 2022 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 2020 Performance Rights In progress 2019 Performance Rights In progress 2018 Performance Rights In progress 2017 Performance Rights Testing completed. Resulted in full vesting of performance rights 69 Beach Energy Limited Annual Report 2021 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 between three and 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, such as accrued leave entitlements. In certain circumstances Beach may terminate employment on notice of not less than between one and three months for issues concerning the senior executive’s performance that have not been satisfactorily addressed. If Beach terminates the senior executive’s appointment other than for cause or he or she resigns due to a permanent relocation of his or her workplace to a location other than their location of hire, then they are entitled to an amount up to one time their final annual salary. Details of total remuneration for KMP calculated as required under the Corporations Act for FY20 and FY21 Legislative and IFRS 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. Remuneration Report (Audited) Details of LTI performance rights issued or in operation in FY21 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: Managing Director and Chief Executive Officer The MD & CEO’s employment agreement commenced with effect 2 May 2016 and is ongoing until terminated by either Beach or Mr Kay on six months’ notice. Beach may terminate the MD & CEO’s employment at any time for cause (for example, for serious breach) without notice. In certain circumstances Beach may terminate the employment on notice of not less than three months for issues concerning the MD & CEO’s performance that have not been satisfactorily addressed. 70 Other long term benefits Long Service Leave (3) $ Total at risk % Total issued in equity % Total $ 52,729 2,223,018 (5,227) 2,600,951 Table 8: Senior executives’ remuneration for FY20 and FY21 as required under the Corporations Act Short Term Employee Benefits Share based payments (1) Name M V Kay Fixed Remuner- ation (2) $ Year 2021 1,202,864 2020 1,266,000 M Engelbrecht 2021 2020 L Marshall I Grant (6) T Nador (7) S Algar (7) 2021 2020 2021 2020 2021 2020 2021 2020 570,954 597,886 524,703 546,591 680,804 – 174,614 – 287,437 – Former Senior Executives G J Barker (8) 2021 2020 J L Schrull (8) D Summers 2021 2020 2021 2020 293,557 486,591 319,934 532,950 – 586,132 Total 2021 4,054,867 2020 4,016,150 Annual Leave (3) $ 22,092 35,358 29,387 (3,439) 7,441 393 29,192 – 2,018 – 18,829 – (16,810) 10,577 (10,297) 28,252 – (12,726) 81,852 58,415 LTI Rights $ 736,372 658,367 174,929 165,574 154,969 142,172 36,349 – 6,553 – 2,292 – (88,815) 140,167 (97,347) 139,631 – (180,191) STI (4) – 143,808 – 44,388 – 33,498 – – – – – – – 28,243 – 36,690 – – – STI Rights (5) $ 208,961 502,645 50,465 109,380 41,018 86,050 126,165 – – – 72,421 – 13,669 (2,231) 4,834 (2,277) – – – – – – 16,201 82,760 (58,817) 95,198 – (72,547) 4,210 (2,277) 10,005 (1,924) – (22,983) 839,404 911,558 732,965 806,427 872,510 – 183,185 – 380,979 – 208,343 746,061 163,478 830,797 – 297,685 925,302 456,414 85,447 5,603,882 286,627 1,065,720 803,486 (36,919) 6,193,479 45 50 28 35 27 32 19 – 4 – 20 – – 33 – 32 – – 26 34 43 45 27 30 27 28 19 – 4 – 20 – – 30 – 28 – – 25 30 (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. In respect of long service leave, the probability weighting for employees with less than 7 years service was reduced during FY20 to better align with Beach’s current average workplace tenure which resulted in a reduction in the provision for all KMP. (4) No STI was payable for FY21. Cash portion of the STI for FY20 was paid in October 2020. (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, divided by a 5 day VWAP as calculated on the relevant anniversary date. (6) Mr Grant became KMP with effect from 20 July 2020. (7) Mr Algar and Mr Nador both became KMP with effect from 23 February 2021. (8) Mr Barker and Mr Schrull both ceased to be KMP on 22 February 2021 although continued to be employed with no decision making rights until 18 July 2021 and 18 May 2021 respectively. 71 Beach Energy Limited Annual Report 2021 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 review by the Remuneration & Nomination Committee a recommendation was made to, and approved by the Board, to leave all non-executive director’s fees unchanged in FY21. However, all non-executive directors reduced their fees by 10% for the period 1 July 2020 – 31 December 2020 in recognition of the COVID-19 impact on the global economy. 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. Details of the fees payable to non-executive directors for Board and committee membership for FY21 are set out in Table 9. Table 9: FY21 non-executive directors’ fees and board committee fees per annum Board (1) Board Committee Chairman/ Deputy Chairman $ Member $ Chairman Audit $ 305,000/122,500 122,500 25,000 Chairman Remuneration and Nomination $ Member Remuneration and Nomination $ Chairman Risk, Corporate Governance and Sustainability $ Member Risk, Corporate Governance and Sustainability $ 25,000 15,000 25,000 15,000 Member Audit $ 15,000 (1) The Chairman does not receive additional fees for committee work. The fees shown are inclusive of the statutory superannuation contribution. 72 Table 10: Non-executive directors’ remuneration for FY20 and FY21 Name G S Davis (1) P J Bainbridge (2) C D Beckett (3) S G Layman (4) P S Moore (5) J C Morton (6) R J Richards (7) R K Stokes (8) M H Hall (9) Total Directors Fees (inc committee fees) $ Superannuation $ 289,750 305,000 127,968 134,703 144,154 155,451 131,167 134,703 132,306 139,269 124,660 131,535 122,965 125,571 130,625 131,535 – – 1,203,595 1,257,767 – – 12,157 12,797 10,221 7,049 8,958 12,797 12,569 13,231 5,965 5,965 11,682 11,929 – 5,965 – – 61,552 69,733 Year 2021 2020 2021 2020 2021 2020 2021 2020 2021 2020 2021 2020 2021 2020 2021 2020 2021 2020 2021 2020 Total $ 289,750 305,000 140,125 147,500 154,375 162,500 140,125 147,500 144,875 152,500 130,625 137,500 134,647 137,500 130,625 137,500 – – 1,265,147 1,327,500 (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 Bainbridge is a member of the Risk, Corporate Governance and Sustainability Committee. Mr Bainbridge ceased as chair of the Risk, Corporate Governance and Sustainability Committee on 25 June 2021. (3) Mr Beckett is Deputy Chairman and chair of the Remuneration and Nomination Committee. He is a member of the Risk, Corporate Governance and Sustainability Committee. (4) Ms Layman is chair of the Audit Committee. (5) Dr Moore is the chair of the Risk, Corporate Governance and Sustainability Committee and a member of the Remuneration and Nomination Committee. Dr Moore became chair of the Risk, Corporate Governance and Sustainability Committee on 25 June 2021, prior to that point he was a member of the committee. (6) Ms Morton is a member of the Audit Committee. (7) Mr Richards is a member of both the Audit Committee and the Risk, Corporate Governance and Sustainability Committee. Mr Richards became a member of the Risk, Corporate Governance and Sustainability Committee on 25 March 2021. (8) Mr Stokes is a member of the Remuneration and Nomination Committee. (9) Ms Hall is an alternate Director for Mr Stokes and does not receive any separate remuneration for this role. 73 Beach Energy Limited Annual Report 2021 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 Opening balance Granted Vested/ exercised Lapsed Other (1) Closing balance Rights MD & CEO M V Kay Senior executives M Engelbrecht I Grant S Algar L Marshall T Nador Former senior executives J L Schrull G J Barker Total 2,565,582 794,559 (255,039) 195,334 181,492 167,736 157,235 64,729 (57,589) – – (261,363) – 634,943 – – 545,641 – 569,697 535,930 – – – – – – – 3,105,102 – – – – 46,691 772,688 181,492 167,736 441,513 111,420 171,491 153,760 (274,269) (251,652) (466,919) (403,091) – (34,947) – – 4,851,793 1,886,336 (1,099,912) (870,010) 11,744 4,779,951 (1) Relates to changes resulting from individuals becoming or ceasing to be KMPs during the period. 74 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 Issued on exercise of performance rights Sold Other (1) Ordinary Shares Directors G S Davis P J Bainbridge C D Beckett M H Hall (2) S G Layman P S Moore J C Morton R J Richards R K Stokes MD & CEO M V Kay Senior executives M Engelbrecht I Grant S Algar T Nador L Marshall Former senior executives J L Schrull G J Barker Total Opening balance 243,226 118,090 81,694 – – 44,200 50,000 188,053 – Purchased 76,875 19,230 9,984 – 45,000 – 24,000 200,000 – – – – – – – – – – 3,663,216 – 255,039 405,634 – – – 10,389 371,010 38,199 5,213,711 – – 76,826 – – – – 57,589 – – – 261,363 274,269 251,652 451,915 1,099,912 (1) Relates to changes resulting from individuals becoming or ceasing to be KMPs during the period. (2) M Hall is an alternate director for Mr Stokes. – – – – – – – – – – – – – – – – – – Closing balance 320,101 137,320 91,678 17,068 45,000 44,200 74,000 388,053 – 3,918,255 463,223 – 76,826 – 271,752 – – – 17,068 – – – – – – – – – – – (645,279) (289,851) (918,062) – – 5,847,476 75 Beach Energy Limited Annual Report 2021 Remuneration Report (Audited) Specific details of the number of LTI and STI performance rights granted, vested/exercised and lapsed in FY21 for KMP are set out in Table 13. Table 13: Details of LTI and STI Performance Rights Fair Value $ Granted Vested/ Exercised Lapsed Other (1) Performance rights on issue at 30 June 2020 849,057 106,130 781,759 148,909 148,909 530,818 – – – 0.6161 1.5314 1.0181 2.5500 2.5300 1.4600 1.8100 1.7900 1.0300 – – – – – – 47,556 47,555 699,448 – (106,130) – (148,909) – – – – – 2,565,582 794,559 (255,039) 247,642 28,268 174,430 29,321 29,321 125,961 – – – 634,943 225,365 10,390 156,157 25,608 25,607 102,514 – – – 545,641 0.6161 1.5314 1.0181 2.5500 2.5300 1.4600 1.8100 1.7900 1.0300 0.7997 1.5314 1.0181 2.5500 2.5300 1.4600 1.8100 1.7900 1.0300 891,631 542,245 – – – – – – 14,679 14,679 165,976 – (28,268) – (29,321) – – – – – 195,334 (57,589) 223,780 118,058 – – – – – – 11,078 11,077 135,080 (225,365) (10,390) – (25,608) – – – – – 157,235 (261,363) 179,011 261,436 Performance rights on issue at 30 June 2021 Date performance rights vest and become exercisable 849,057 – 781,759 – 148,909 530,818 47,556 47,555 699,448 3,105,102 247,642 – 174,430 – 29,321 125,961 14,679 14,679 165,976 772,688 – – 156,157 – 25,607 102,514 11,078 11,077 135,080 441,513 1 Dec 2020 1 Jul 2020 1 Dec 2021 1 Jul 2020 1 Jul 2021 1 Dec 2022 1 Jul 2021 1 Jul 2022 1 Dec 2023 1 Dec 2020 1 Jul 2020 1 Dec 2021 1 Jul 2020 1 Jul 2021 1 Dec 2022 1 Jul 2021 1 Jul 2022 1 Dec 2023 1 Dec 2020 1 Jul 2020 1 Dec 2021 1 Jul 2020 1 Jul 2021 1 Dec 2022 1 Jul 2021 1 Jul 2022 1 Dec 2023 – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – – Date of grant 1 Dec 2017 6 Dec 2018 14 Dec 2018 19 Dec 2019 19 Dec 2019 19 Dec 2019 25 Nov 2020 25 Nov 2020 14 Dec 2020 1 Dec 2017 6 Dec 2018 14 Dec 2018 19 Dec 2019 19 Dec 2019 19 Dec 2019 25 Nov 2020 25 Nov 2020 14 Dec 2020 9 Apr 2018 6 Dec 2018 14 Dec 2018 19 Dec 2019 19 Dec 2019 19 Dec 2019 25 Nov 2020 25 Nov 2020 14 Dec 2020 Name M V Kay Total Total ($) M Engelbrecht Total Total ($) L Marshall Total Total ($) 76 Performance rights on issue at 30 June 2020 Name Date of grant Fair Value $ Granted Vested/ Exercised Lapsed Other (1) Performance rights on issue at 30 June 2021 Date performance rights vest and become exercisable 9 Apr 2018 6 Dec 2018 14 Dec 2018 19 Dec 2019 19 Dec 2019 19 Dec 2019 25 Nov 2020 25 Nov 2020 14 Dec 2020 1 Dec 2017 6 Dec 2018 14 Dec 2018 19 Dec 2019 19 Dec 2019 19 Dec 2019 25 Nov 2020 25 Nov 2020 14 Dec 2020 14 Dec 2020 14 Dec 2020 3 May 2021 3 May 2021 G J Barker Total Total ($) J L Schrull Total Total ($) I Grant Total Total ($) T Nador Total Total ($) S Algar Total Total ($) 217,845 8,199 156,157 25,608 25,607 102,514 – – – 535,930 224,057 24,332 157,818 25,880 25,880 111,730 – – – 569,697 – – – – – – – 0.7997 1.5314 1.0181 2.5500 2.5300 1.4600 1.8100 1.7900 1.0300 0.6161 1.5314 1.0181 2.5500 2.5300 1.4600 1.8100 1.7900 1.0300 1.0300 1.0300 0.4100 0.4100 – – – – – – 9,340 9,340 135,080 (217,845) (8,199) – (25,608) – – – – – – – (156,157) – – (102,514) – (9,340) (135,080) – – – – (25,607) – (9,340) – – 153,760 (251,652) (403,091) (34,947) 172,756 252,067 – – – – – – 12,134 12,133 147,224 (224,057) (24,332) – (25,880) – – – – – – – (157,818) – (25,880) (111,730) (12,134) (12,133) (147,224) 171,491 (274,269) (466,919) 195,321 181,492 181,492 186,937 – 64,729 64,729 26,539 167,736 167,736 68,772 241,298 – – – – – – – – – – – – – – – – – – – – – – – – – – – – – 46,691 – 46,691 – – (1) Relates to changes resulting from individuals becoming or ceasing to be KMPs during the period. 1 Dec 2020 1 Jul 2020 1 Dec 2021 1 Jul 2020 1 Jul 2021 1 Dec 2022 1 Jul 2021 1 Jul 2022 1 Dec 2023 1 Dec 2020 1 Jul 2020 1 Dec 2021 1 Jul 2020 1 Jul 2021 1 Dec 2022 1 Jul 2021 1 Jul 2022 1 Dec 2023 – – – – – – – – – – – – – – – – – – – – 181,492 1 Dec 2023 181,492 46,691 64,729 111,420 1 Dec 2023 1 Dec 2023 167,736 1 Dec 2023 167,736 77 Beach Energy Limited Annual Report 2021 Flexible Work Arrangements New Flexible Work Arrangements (FWA) procedures and leader guides were implemented across Beach in FY21. FWA arrangements are an important way to offer an environment which supports diversity and inclusion at work, whilst also ensuring the business meets legislative requirements in Australia and New Zealand operations. In addition, the FWA arrangements have supported the Beach response to COVID-19 orders across multiple jurisdictions, ensuring employees are aware of the multiple work arrangements at their disposal. Remuneration Report (Audited) Looking ahead – Remuneration and related issues for 2022 Superannuation guarantee Effective from 1 July 2021, the Superannuation Guarantee (SG) minimum compulsory rate for all Australian employees is legislated to increase from 9.5% to 10%. 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 was not increased as part of the SG increase, the rate change to superannuation instead deducted from base salary. Employee Retention The ability to attract and retain the workforce will remain of critical importance as Beach seeks to ensure our planning and engagement practices are optimised to deliver operational and project priorities. Activities in areas including engagement, remuneration, wellbeing and resourcing practices will continue to be optimised with any improvement opportunities identified in these areas being applied. Leadership Development Several leadership programs have been developed and deployed throughout FY21 and will continue in FY22. Examples being the Front Line Leadership Program which was deployed in a self-paced manner to our operational sites and includes a module on situational (safety) leadership with the participants being highly engaged. Beach has also implemented an Unconscious Bias online module for all employees, which focusses on effective decision making and ensuring all ideas and approaches are included for consideration to optimise business decisions. This will progress into face to face training, with practical tool application in FY22. 78 Directors’ Declaration 1. In the directors’ opinion: (a) t he financial statements and notes set out on pages 80 to 124 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 2021 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 2021. 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 16 August 2021 79 Beach Energy Limited Annual Report 2021 Consolidated Statement of Profit or Loss and Other Comprehensive Income For the financial year ended 30 June 2021 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 FCTR release on cessation of overseas operations 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 2021 $million 1,562.0 (967.1) 594.9 51.1 (203.7) 442.3 0.9 (6.4) 436.8 (120.3) 316.5 – 0.3 0.3 316.8 13.88¢ 13.87¢ 2020 $million 1,728.2 (1,056.7) 671.5 76.6 (43.5) 704.6 2.0 (16.0) 690.6 (191.5) 499.1 (8.7) (4.9) (13.6) 485.5 21.89¢ 21.84¢ Note 2(a) 3(a) 2(b) 3(b) 16 16 5 26 6 6 80 Consolidated Statement of Financial Position As at 30 June 2021 Current assets Cash and cash equivalents Receivables Inventories Contract assets Other Total current assets Non-current assets Property, plant and equipment Petroleum assets Exploration and evaluation assets Intangible assets Deferred tax 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 Contract 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. Consolidated Note 2021 $million 2020 $million 17 18 7 8 9 10 11 5 14 18 13 14 18 13 16 5 14 19 20 126.7 355.0 99.4 16.2 73.6 670.9 8.6 3,431.6 334.8 77.1 – 72.2 38.8 45.2 4,008.3 4,679.2 263.2 42.9 3.9 77.0 12.0 399.0 4.5 939.5 174.1 44.4 26.0 3.9 1,192.4 1,591.4 3,087.8 1,859.5 867.1 361.2 3,087.8 109.9 215.8 106.9 16.0 59.0 507.6 9.6 2,986.5 462.4 78.8 33.6 58.7 49.3 25.8 3,704.7 4,212.3 276.4 30.9 86.4 26.8 35.7 456.2 5.6 798.9 56.7 29.3 35.3 12.5 938.3 1,394.5 2,817.8 1,861.2 911.9 44.7 2,817.8 81 Beach Energy Limited Annual Report 2021 Consolidated Statement of Changes in Equity For the financial year ended 30 June 2021 Share based payment reserve $million 32.8 – – – – – – – – 3.2 3.2 Foreign currency translation reserve $million 8.3 – (13.6) (13.6) – – – – – – – 36.0 (5.3) Profit distribution reserve $million 126.8 – – – – – (22.8) (22.8) 800.0 – 754.4 881.2 – – – – – – (22.8) (22.8) – (45.6) Total $million 2,374.1 499.1 (13.6) 485.5 1.3 (0.7) (22.8) (22.8) – 3.2 (41.8) 2,817.8 316.5 0.3 316.8 0.2 (4.0) – (22.8) (22.8) 2.6 (46.8) – 0.3 0.3 – – – – – – – (5.0) 835.6 3,087.8 – – – – – (2.1) – – 2.6 0.5 36.5 Contributed equity $million Retained earnings $million Note Balance as at 30 June 2019 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) Final dividend paid Interim dividend paid Transfer to profit distribution reserve Increase in share based payments reserve Transactions with owners Balance as at 30 June 2020 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 2021 19 19 21 21 19 19 19 21 21 1,860.6 – – – 1.3 (0.7) – – – – 0.6 1,861.2 – – – 0.2 (4.0) 2.1 – – – (1.7) 345.6 499.1 – 499.1 – – – – (800.0) – (800.0) 44.7 316.5 – 316.5 – – – – – – – 1,859.5 361.2 The accompanying notes form part of these financial statements. 82 Consolidated Statement of Cash Flows For the financial year ended 30 June 2021 Cash flows from operating activities Receipts from customers and other Payments to suppliers and employees 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 from government grants Proceeds on sale of joint operations interests Proceeds from sale of non-current assets Payments for acquisition of joint operations 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 2021 $million 2020 $million 1,624.3 (692.6) (12.7) 0.2 (6.5) (152.9) 17 759.8 26 26 17 17 21 (1.1) (529.2) (139.4) (3.9) – – – (84.2) (757.8) 260.0 (145.0) (42.9) 0.2 (5.7) (45.6) 21.0 23.0 109.9 (6.2) 126.7 1,913.2 (761.7) (7.9) 2.2 (7.2) (264.7) 873.9 (5.1) (643.1) (266.1) (5.8) 11.3 8.9 0.7 – (899.2) 225.0 (165.0) (54.2) 1.4 (1.0) (45.6) (39.4) (64.7) 171.9 2.7 109.9 83 Beach Energy Limited Annual Report 2021 Notes to the Financial Statements Notes to and forming part of the Financial Statements for the financial year ended 30 June 2021 Basis of preparation 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. 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 2021 was authorised for issue in accordance with a resolution of the directors on 16 August 2021. 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. Notes to the financial statements 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. 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 the COVID-19 pandemic and other 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 Going concern The Group ended FY21 with $127 million in cash, drawn debt of $175 million and net working capital of $272 million (current assets less current liabilities). Available liquidity was $402 million, comprising $127 million in cash and $275 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 to 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. 84 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. 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 except for the acquisitions noted in Note 26 that have applied the optional concentration test under AASB 3 Business Combinations. AASB 2018-6 Amendments to Australian Accounting Standards – Definition of a Business The amendments update the definition of a business in AASB 3 Business Combinations to help determine whether an acquired set of activities and assets is a business or not. They clarify the minimum requirements for a business, remove the assessment of whether market participants are capable of replacing any missing elements, add guidance to help entities assess whether an acquired process is substantive, narrow the definitions of a business and of outputs, and introduce an optional fair value concentration test. AASB 2019-3 Amendments to Australian Accounting Standards – Interest Rate Benchmark Reform The amendments to AASB 9 Financial Instruments were issued in response to the effects of Interbank Offered Rates reform on financial reporting and provide mandatory temporary reliefs which enable hedge accounting to continue during the period of uncertainty before the replacement of an existing interest rate benchmark with an alternative nearly risk-free interest rate. AASB 2018-7 Amendments to Australian Accounting Standards – Definition of Material This Standard amends AASB 101 Presentation of Financial Statements and AASB 108 Accounting Policies, Changes in Accounting Estimates and Errors to align the definition of ‘material’ across the standards and to clarify certain aspects of the definition. The new definition states that, ’Information is material if omitting, misstating or obscuring it could reasonably be expected to influence decisions that the primary users of general purpose financial statements make on the basis of those financial statements, which provide financial information about a specific reporting entity.’ The Conceptual Framework for Financial Reporting The revised Conceptual Framework for Financial Reporting (the Conceptual Framework) is not a standard, and none of the concepts override those in any standard or any requirements in a standard. The purpose of the Conceptual Framework is to assist the Accounting Standards Board in developing standards, to help preparers develop consistent accounting policies if there is no applicable standard in place and to assist all parties to understand and interpret the standards. The Conceptual Framework includes some new concepts, provides updated definitions and recognition criteria for assets and liabilities, and clarifies some important concepts. 85 Beach Energy Limited Annual Report 2021 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. 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. These amendments are not expected to have immediate material impact on the Group’s annual consolidated financial statements. Standard Amendments Interest Rate Benchmark Reform – Phase 2 – Amendments to IFRS 9, IAS 39, IFRS 7, IFRS 4 and IFRS 16 Reference to the Conceptual Framework – Amendments to IFRS 3 Property, Plant and Equipment: Proceeds before intended use – Amendments to IAS 16 Onerous Contracts – Costs of Fulfilling a Contract – Amendments to IAS 37 Classification of Liabilities as Current or Non-Current – Amendments to IAS 1 Application of standard 1 July 2021 1 July 2022 1 July 2022 1 July 2022 1 July 2023 Deferred Tax related to Assets and Liabilities arising from a Single Transaction – Amendments to IAS 12 1 July 2023 Impact on previous reporting periods Change in accounting policy IFRIC agenda decision – Configuration or Customisation Costs in a Cloud Computing Arrangement In April 2021, the IFRS Interpretations Committee (IFRIC) published an agenda decision for configuration and customisation costs incurred related to a Software as a Service (SaaS) arrangement. The Group has changed its accounting policy in relation to configuration and customisation costs incurred in implementing SaaS arrangements. The nature and effect of the changes as a result of changing this policy is described below. SaaS arrangements are arrangements in which the Group does not currently control the underlying software used in the arrangement. Where costs incurred to configure or customise SaaS arrangements 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 and 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. Where costs incurred to configure or customise do not result in the recognition of an intangible software asset, then those costs that provide the Group with a distinct service (in addition to the SaaS access) are now recognised as expenses when the supplier provides the services. When such costs incurred do not provide a distinct service, the costs are now recognised as expenses over the duration of the SaaS contract. Previously some costs had been capitalised and amortised over its useful life. The change in policy has been retrospectively applied and comparative financial information has been restated, as follows: Prior period restatements 30 June 2020 $million 30 June 2019 $million (2.5) (2.5) 0.8 0.8 (1.7) (2.5) 0.8 (1.7) (0.4) (0.4) 0.1 0.1 (0.3) (0.4) 0.1 (0.3) Impact on equity – increase/(decrease) in equity Intangible Assets Total Assets Deferred Tax Liability Total Liabilities Net impact on equity Impact on statement of profit or loss – increase/(decrease) in profit Other expenses Income tax expense Net profit after tax 86 Notes to the Financial Statements 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 and Western Australian (SAWA), 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 Managing Director & 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 2021 and 30 June 2020 are as follows: SAWA Victoria New Zealand Total 2021 $million 2020 $million 2021 $million 2020 $million 2021 $million 2020 $million 2021 $million 2020 $million Segment revenue Revenue from external customers (1) Segment results Gross segment result before depreciation, amortisation and impairment Depreciation and amortisation Impairment expense Other revenue Other income Net financing costs Other expenses Profit before tax Income tax expense Net profit after tax 1,177.8 1,288.1 207.1 222.3 134.5 139.9 1,519.4 1,650.3 709.8 (267.3) (117.0) 325.5 813.2 (329.1) – 484.1 134.8 (117.3) – 17.5 153.8 (90.1) – 63.7 125.9 (33.6) – 92.3 71.5 (25.7) (1.6) 44.2 970.5 (418.2) (117.0) 435.3 42.6 51.1 (5.5) (86.7) 436.8 (120.3) 316.5 1,038.5 (444.9) (1.6) 592.0 77.9 76.6 (14.0) (41.9) 690.6 (191.5) 499.1 (1) During the year revenue from three customers amounted to $989 million (2020: $1,231 million from three customers) arising from sales from SAWA, Victoria and New Zealand segments. 87 Beach Energy Limited Annual Report 2021 1. Operating segments (continued) SAWA Victoria New Zealand Total 2021 $million 2020 $million 2021 $million 2020 $million 2021 $million 2020 $million 2021 $million 2020 $million 2,967.7 2,739.7 1,224.9 896.4 287.8 277.6 4,480.4 3,913.7 584.1 502.8 506.4 353.8 106.8 123.3 198.8 4,679.2 1,197.3 394.1 1,591.4 298.6 4,212.3 979.9 414.6 1,394.5 96.7 349.3 446.0 175.7 447.5 623.2 45.2 261.7 306.9 21.6 125.7 147.3 0.7 23.1 23.8 21.2 18.5 39.7 142.6 634.1 776.7 218.5 591.7 810.2 33.4 18.6 810.1 828.8 Australia New Zealand Total 2021 $million 3,753.4 2020 $million 3,407.7 2021 $million 209.7 2020 $million 237.6 2021 $million 3,963.1 2020 $million 3,645.3 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 Non-current assets* *excluding financial assets and deferred taxes 88 Notes to the Financial Statements 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 and liabilities have increased by $22.0 million to $39.1 million, with $20.4 million included in other revenue and $3.3 million unwind of discount included in finance expenses offset by $1.7 million included in FCTR. (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 2021 totalled $110.9 million (FY20 $89.1 million). Consolidated 2021 $million 2020 $million 613.6 609.4 130.5 143.6 883.5 1,497.1 22.3 1,519.4 42.6 1,562.0 818.7 604.8 119.1 145.2 869.1 1,687.8 (37.5) 1,650.3 77.9 1,728.2 89 Beach Energy Limited Annual Report 2021 2. Revenue from contracts with customers and other income (continued) (b) Other income Gain on sale of joint operations interests (Note 26) Gain on cessation of overseas operations (Note 26) Gain on reversal of acquired liabilities 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 2021 $million 2020 $million – – 35.4 – 9.8 5.3 – 0.6 51.1 8.9 8.7 37.8 0.6 15.5 3.7 1.4 – 76.6 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 Impairment Impairment of petroleum assets (Note 9) Impairment of exploration and evaluation assets (Note 10) Total impairment expense Other Exploration expense Loss on sale of non-current assets Depreciation of corporate leased assets (Note 14) Foreign exchange losses Corporate expenses (1) Other expenses Total other expenses Consolidated 2021 $million 2020 $million 251.8 76.0 116.9 444.7 405.6 12.6 68.4 35.8 967.1 35.3 81.7 117.0 56.7 1.7 3.5 8.9 15.9 86.7 203.7 240.4 160.9 124.3 525.6 427.1 17.8 93.0 (6.8) 1,056.7 – 1.6 1.6 20.7 – 3.5 – 17.7 41.9 43.5 (1) Includes depreciation of property, plant and equipment and amortisation of software costs of $7.3 million (FY20 $6.3 million) as shown in Note 8 and 11, and share based payments expense of $2.6 million (FY20 $3.3 million). 90 Notes to the Financial Statements 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 2019 Loans repaid during 2020 financial year Balance as at 30 June 2020 Loans repaid during 2021 financial year Balance as at 30 June 2021 Number 2,541,488 (1,003,200) 1,538,288 (150,850) 1,387,438 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 2021 was $1.24 as compared to $1.52 as at 30 June 2020. 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. Details of shares purchased and utilised under this plan are detailed in Note 19. 91 Beach Energy Limited Annual Report 2021 4. Employee benefits (continued) 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 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. Details of the key assumptions used in determining the valuation of unlisted performance rights issued during the year are outlined below. 2019 STI Rights 2019 STI Rights 2019 LTI Rights 2020 LTI Rights 2020 LTI Rights FY21 ESP (1) Grant date 25 Nov 2020 25 Nov 2020 14 Dec 2020 14 Dec 2020 Vesting date Expiry date Share price at grant date (A$) Exercise price (A$) Expected volatility (average) Vesting Period (years) Risk free rate Dividend yield Number of securities issued Fair value of security at grant date (A$) Total fair value at grant date 1 Jul 2021 n/a 1.82 Nil n/a 0.6 n/a 1.10% 131,602 1.81 238,120 1 Jul 2022 n/a 1.82 Nil n/a 1.6 n/a 1.10% 131,597 1.79 235,559 1 Dec 2022 1 Dec 2023 30 Nov 2024 30 Nov 2025 1.90 Nil 59.5% 3.0 0.10% 1.05% 1.90 Nil 59.5% 2.0 0.04% 1.05% 31 May 2021 Up to 30 Jun 2021 1 Jul 2023 1 Dec 2023 n/a 30 Nov 2025 1.18 – 1.81 1.27 Nil Nil n/a 53.2% 2.0 – 2.9 2.5 0.05% n/a 1.57% 1.11% – 1.69% 28,619 0.88 25,185 2,331,931 1.03 2,401,889 311,722 0.41 127,806 821,546 1.13 – 1.76 1,178,590 (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: Consolidated 2021 number 7,437,135 3,757,017 (1,414,684) (1,595,129) 2020 number 7,711,875 3,178,907 (873,846) (2,579,801) 8,184,339 7,437,135 Balance at beginning of period Issued during the period Forfeited during the period Vested/Exercised during the period Balance at end of period 92 Notes to the Financial Statements 5. Taxation Australian income tax consolidation 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. 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. 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. 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. 93 Beach Energy Limited Annual Report 2021 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 2021 $million 2020 $million 99.2 (25.6) 73.6 20.7 26.0 46.7 120.3 173.5 (23.6) 149.9 29.2 12.4 41.6 191.5 (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 Over provision in prior years Income tax expense reported in the Statement of Profit or Loss Consolidated 2021 $million 436.8 131.0 2020 $million 690.6 207.1 0.9 (2.1) (9.9) 0.4 120.3 1.5 (0.8) (5.1) (11.2) 191.5 94 Notes to the Financial Statements (c) Income tax related to items charged or credited to equity ($million) Share based equity (d) Deferred tax assets and liabilities ($million) Recognised deferred tax assets and liabilities Oil & Gas Assets Provisions Employee benefits Tax Losses Leases Other Items Tax assets/(liabilities) Set-off of tax Net deferred tax assets/(liabilities) Consolidated 2021 $million 2020 $million (1.7) (0.3) Assets Liabilities Net 2021 $million 2020 $million 2021 $million 2020 $million 2021 $million 2020 $million – 287.0 6.1 2.8 30.9 8.1 334.9 (334.9) – 7.3 259.4 5.4 3.8 26.4 6.6 308.9 (275.3) 33.6 (301.8) – – – (10.1) (67.4) (379.3) 334.9 (44.4) (239.6) (18.3) – – (25.4) (21.3) (304.6) 275.3 (29.3) (301.8) 287.0 6.1 2.8 20.8 (59.3) (44.4) – (44.4) (232.3) 241.1 5.4 3.8 1.0 (14.7) 4.3 – 4.3 95 Beach Energy Limited Annual Report 2021 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 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 2021 $million 316.5 2020 $million 499.1 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) 2021 Number 2020 Number 2,279,860,248 2,279,909,473 2,118,934 5,277,121 2,281,979,182 2,285,186,594 13.88¢ 13.87¢ 21.89¢ 21.84¢ 5,178,791 (FY20 1,602,015 ) 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. 96 Notes to the Financial Statements 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 2021 $million 2020 $million 37.7 65.5 (3.8) 99.4 – 63.4 48.0 (4.5) 106.9 22.9 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 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 4–33%. 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 2021 $million 2020 $million 14.4 2.0 (7.8) 8.6 9.6 0.7 (1.7) 8.6 13.6 2.1 (6.1) 9.6 5.1 5.4 (0.9) 9.6 97 Beach Energy Limited Annual Report 2021 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 3–67% 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. 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 producing the reserves. 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 and Society of Petroleum Evaluation Engineers (SPE-PRMS). 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 2021 have been independently audited by RISC Advisory in accordance with Beach’s reserves policy. Reserves and resources estimates 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 and engineering information becomes available through additional drilling or subsurface 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. Field land and buildings Land and buildings at cost Less accumulated depreciation Total 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 98 Consolidated 2021 $million 2020 $million 78.7 (22.3) 56.4 54.8 4.0 (2.3) (0.1) 56.4 74.8 (20.0) 54.8 51.2 5.3 (1.4) (0.3) 54.8 2,090.9 89.9 (996.4) 1,184.4 1,918.7 146.9 (898.8) 1,166.8 Notes to the Financial Statements 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) Impairment of production facilities and field equipment 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 Transfer from exploration and evaluation assets Impairment of subsurface assets Borrowing costs capitalised Foreign exchange movement Amortisation expense Disposals Capitalised depreciation of lease assets Total subsurface assets Total petroleum assets Consolidated 2021 $million 2020 $million 1,166.8 105.4 30.2 (17.7) (98.1) (0.2) (2.0) 1,184.4 1,088.8 150.4 – – (67.5) – (4.9) 1,166.8 4,031.8 451.0 (2,292.0) 3,229.3 522.5 (1,986.9) 2,190.8 1,764.9 1,764.9 406.8 87.7 53.3 180.8 (17.6) 7.1 (0.1) (305.2) (1.5) 14.6 2,190.8 3,431.6 1,586.7 436.1 – (32.5) 102.6 – 6.1 0.5 (358.2) (0.4) 24.0 1,764.9 2,986.5 The carrying amounts of petroleum assets are assessed half yearly to determine whether there is an indication of impairment or impairment reversal for those assets which have previously been impaired. Indicators of impairment and impairment reversals include changes in future selling prices, future costs and reserves. 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. Petroleum assets are assessed for impairment indicators on a cash generating unit (CGU) basis. 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. 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 after taking into account the risks specific to the asset and discounting it to its present value using an appropriate discount rate. 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. 99 Beach Energy Limited Annual Report 2021 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$70.50/bbl in FY22, US$67.50/bbl for FY23, US$67.00/bbl for FY24, US$66.50/bbl for FY25, US$64/bbl for FY26 and US$60/bbl for FY27 and beyond. – A$/US$ exchange rate of 0.78 for FY22 and 0.75 for FY23 and beyond. – Post-tax real discount rate of 7%. 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. With the planned suspension of operations at the Katnook Gas Plant due to low gas volumes with lower than originally expected economic ultimate recovery of gas for the Haselgrove field, an impairment expense of $35.3 million has been recorded against the carrying value of petroleum assets for the SA Otway CGU which is part of the SAWA operating segment. This impairment charge has been recognised within other expenses in the statement of profit or loss and other comprehensive income. The recoverable amount of the SA Otway CGU based on 2P reserves and a risked outcome on contingent resources is $62 million which represents the carrying value of exploration assets before deducting the carrying value of restoration liabilities and has been calculated using the value in use method with all petroleum assets impaired to nil. 9. Petroleum assets (continued) Future cash flow information used for the value in use calculation is based on the Group’s latest reserves, budget, five-year plan and project economic plans which includes information sourced and reviewed from operators of our non-operated interests. The South Australia Otway was included as a producing CGU for the first time in FY20 with the Katnook plant commissioned and commencement of production in H2 FY20 through the Haselgrove 3 field. As the Katnook gas plant was constructed to facilitate the processing of gas across a number of fields, a conservative view of additional resources for other wells and their development costs has been included into the NPV calculation and assessed against a carrying value including additional exploration transfers to development for these further assumed 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. Notwithstanding that there is currently no price on carbon in Australia, the Group has further assessed the carrying value of its producing assets in Australia against NPVs including a carbon pricing slope of $25/tCO2e increasing to A$50/tCO2e by 2030 then increasing to A$70/tCO2e by 2040 (real) and incorporating the benefits of carbon capture and storage and the delivery of projects related to Beach’s ‘25 by 25’ initiative which would also not result in any impairment being required as at 30 June 2021 had this been in place. 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 and external market analyst’s forecasts. 100 Notes to the Financial Statements 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 recoverability of the carrying amount of the exploration and evaluation assets is dependent on successful development and commercial exploitation, or alternatively, sale of the respective AOI. Each potential or recognised AOI is reviewed half-yearly to determine whether economic quantities of reserves have been found or whether further exploration and evaluation work is underway or planned to support continued carry forward of capitalised costs. 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 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. With the planned suspension of operations at the Katnook Gas Plant due to low gas volumes with lower than originally expected economic ultimate recovery of gas for the Haselgrove field, an impairment expense of $81.7 million has been recorded against the carrying value of exploration and evaluation assets for the SA Otway CGU which is part of the SAWA operating segment. This impairment charge has been recognised within other expenses in the statement of profit or loss and other comprehensive income. The recoverable amount of the SA Otway CGU based on 2P reserves and a risked outcome on contingent resources is $62 million which represents the carrying value of exploration assets before deducting the carrying value of restoration liabilities and has been calculated using the value in use method. Exploration and evaluation assets at beginning of financial year Additions Increase/(decrease) in restoration Acquisition of assets and joint operation interests (Note 26) Transfer to petroleum assets Impairment of exploration and evaluation assets Exploration and evaluation expenditure expensed Disposal of joint operation interests Borrowing costs capitalised Foreign exchange movement Capitalised depreciation of lease assets Total exploration and evaluation assets Consolidated 2021 $million 2020 $million 462.4 126.5 4.2 48.8 (180.8) (81.7) (56.7) (0.4) – (0.2) 12.7 334.8 355.3 231.5 (9.5) 0.1 (102.6) (1.6) (20.7) (2.2) 0.4 0.3 11.4 462.4 101 Beach Energy Limited Annual Report 2021 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. Amortisation methods and useful lives The group amortises intangible assets with a limited useful life using the straight-line method over the following periods: – IT software – 5 years At Cost Accumulated Amortisation Intangible Assets at 30 June 2021 Reconciliation of movement in intangible assets Balance at beginning of financial year Additions Amortisation Intangible Assets at 30 June 2021 At Cost Accumulated Amortisation Intangible Assets at 30 June 2020 Reconciliation of movement in intangible assets Balance at beginning of financial year Additions Amortisation Intangible Assets at 30 June 2020 12. Interests in joint operations Goodwill $ million Software $ million Total $ million 57.1 – 57.1 57.1 – – 57.1 39.8 (19.8) 20.0 21.7 3.9 (5.6) 20.0 96.9 (19.8) 77.1 78.8 3.9 (5.6) 77.1 Goodwill $ million Software $ million Total $ million 57.1 – 57.1 57.1 – – 57.1 35.9 (14.2) 21.7 21.3 5.8 (5.4) 21.7 93.0 (14.2) 78.8 78.4 5.8 (5.4) 78.8 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. 102 Notes to the Financial Statements 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) PEL 630 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) (1) 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 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 2021 2020 75.0 40.0 40.0 50.0 33.4 33.4 38.5 40.0 30.0 39.9 75.0 40.0 40.0 50.0 33.4 33.4 38.5 40.0 30.0 39.9 60.0 60.0 88.8 90.3 50.0 50.0 53.8 50.3 50.0 50.0 Gas production 50.0 50.0 (1) Increased ownership interests shown at 30 June 2021 were subject to completion on 31 July 2021 of the acquisition of Mitsui’s interests in the Bass Basin under an asset purchase agreement executed in January 2021. Details of commitments for expenditure and contingent liabilities incorporating the Group’s interests in joint operations are shown in Notes 15 and 27 respectively. 103 Beach Energy Limited Annual Report 2021 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 costs which are not included in our best estimate and the associated provision recorded at 30 June 2021. Actual costs and cash outflows can differ from current estimates because of changes in laws and regulations, public expectations, prices, discovery and analysis of site conditions and changes in clean-up technology. The timing and amount of future expenditures relating to decommissioning and environmental liabilities are reviewed annually, together with the interest rate used in discounting the cash flows. The interest rates used to determine the balance sheet obligations at 30 June 2021 were within the range 0.0% to 2.2% (2020 within the range 0.3% to 1.5%), and were based on applicable government bonds with a tenure aligned to the tenure of the liability. Given the continuing lack of correlation between long term inflation rate forecasts and nominal long term bond rates, management have revised their inflation rate assumptions to reflect the lower long term bond rates in the current environment. Changes in assumptions in relation to the Group’s provisions 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 –$60/+$10 million respectively on the value of the Group’s provisions. The impact on the Group income statement would not be significant as the majority of the Group’s provisions relate to decommissioning costs with adjustments recorded against the carrying value of the Group’s assets. 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 and the provision revised at the end of each reporting period through the profit or loss as the discounting of the liability unwinds. The unwinding of discounting on the provision is recognised as a finance cost. 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. Any changes in the expected future costs are reflected in both the provision and the asset. The provision for environmental liabilities represents the Group’s best estimate based on current industry practice, current 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 nearshore 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 all subsea piles 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. 104 Notes to the Financial Statements 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. Current Employee entitlements Restoration Total Non-Current Employee entitlements Restoration Total Movement in the Group’s provisions are set out below: Balance at 1 July 2020 Provision made or reversed during the year Provision paid/used during the year Unwind of discount Acquisitions/disposals Foreign exchange movements Balance at 30 June 2021 Consolidated 2021 $million 2020 $million 19.5 23.4 42.9 0.8 938.7 939.5 16.9 14.0 30.9 1.0 797.9 798.9 Restoration $million Employee entitle- ments $million 811.9 57.6 (11.6) 8.1 95.7 0.4 962.1 17.9 9.1 (6.7) – – – 20.3 105 Beach Energy Limited Annual Report 2021 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. 106 Notes to the Financial Statements 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 2021 $million 2020 $million 58.7 70.2 (13.3) (43.4) 72.2 96.8 30.1 (11.5) (56.7) 58.7 (1) Instances where the underlying costs regarding a lease contract would previously have been capitalised, the depreciation on the lease asset is capitalised. The Group capitalisation of depreciation is $27.3m. 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 2021 $million 2020 $million 62.1 103.7 (53.8) (13.3) 2.0 2.3 103.0 77.0 26.0 96.8 30.1 (57.6) (11.5) 3.4 0.9 62.1 26.8 35.3 (2) (3) 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 $9.8m of other income relating to joint venture recoveries. 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. The Group received $9.0m of sublease repayments from other parties and has a sublease receivable of $25.6m at 30 June 2021. Payments of $42 million for short-term leases (lease term of 12 months or less) and payments of $6 million for leases of low value assets were also accounted for in the year ended 30 June 2021. 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. For the year ending 30 June 2021, the amount recognised was $9.8 million. 107 Beach Energy Limited Annual Report 2021 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 2021 $million 2020 $million 69.6 – – 69.6 48.6 – – 48.6 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 2021 $million 2020 $million 35.2 47.0 4.2 86.4 25.4 51.5 4.1 81.0 The Group’s share of the above commitments that relate to its interest in joint arrangements are $68.3 million (FY20 $43.8 million) for capital commitments and $25.0 million (FY20 $80.6 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. Lease Commitments The Group has contracted the following amounts for lease commitments at the end of the reporting period for which no amounts have been provided for in the financial statements. Consolidated 2021 $million 2020 $million – – 14.7 14.7 Due within 1 year 108 Notes to the Financial Statements 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 income statement. 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 balance sheet 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 2021 $million 2020 $million 4.4 2.3 4.8 2.0 (7.1) 6.4 (0.9) 5.5 175.0 (0.9) 174.1 6.0 0.7 12.4 3.4 (6.5) 16.0 (2.0) 14.0 60.0 (3.3) 56.7 Beach currently has a Senior Secured Debt Facility in place for $525 million, comprised of a $450 million revolving debt facility (Facility C) and a $75 million Letter of Credit facility (Facility D), both of which have a maturity date of November 2022. As at 30 June 2021 $175 million of Facility C was drawn with $275 million remaining undrawn, with $73 million of Facility D being utilised predominantly by way of bank guarantees. Bank debt bears interest at the relevant reference rate plus a margin, with the effective interest rate in FY21 of 1.48% (FY20 2.06%). 109 Beach Energy Limited Annual Report 2021 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 – Recognition of deferred tax assets on items direct in equity Add/(less) non-cash items: – Share based payments – Depreciation and amortisation Impairment expense – – Exploration expense – Foreign exchange loss – Discount unwinding on provision for restoration – Provision for stock obsolescence movement – Gain on reversal of acquired liabilities – Gain on cessation of overseas operations – 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 other current assets – Decrease/(increase) in other non-current assets – Decrease/(increase) in deferred tax assets – – – – – 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 net contract liabilities Net cash provided by operating activities (c) Reconciliation of liabilities arising from financing activities to financing cash flows Opening Balance Financing cash flows (1) Non-cash changes Closing Balance Consolidated 2021 $million 2020 $million 126.7 126.7 109.9 109.9 316.5 499.1 0.8 0.9 – (0.6) (8.9) 0.8 318.2 490.4 2.6 429.5 117.0 56.7 0.8 8.1 (0.7) (35.4) – (6.6) 2.4 892.6 (96.5) 14.6 (28.6) (18.8) 33.6 (10.6) (80.9) 15.1 62.2 (22.9) 759.8 56.7 115.0 2.4 174.1 3.3 454.8 1.6 20.7 1.0 11.9 4.2 (37.8) (8.7) (6.5) 2.7 937.6 61.7 (11.6) (39.3) (16.1) 46.1 (0.4) (114.9) (5.7) 63.9 (47.4) 873.9 – 60.0 (3.3) 56.7 (1) Financing cash flows consist of the net amount of proceeds from borrowing ($260 million) and repayments of borrowings ($145 million) in the statement of cash flows. 110 Notes to the Financial Statements 18. Financial risk management The Group’s activities expose it to a variety of financial risks including currency, commodity, interest rate, credit and liquidity risk. Management identifies and evaluates all financial risks and may enter into financial risk instruments such as foreign exchange contracts, commodity contracts and interest rate swaps to hedge certain risk exposures and minimise potential adverse effects of these risk exposures in accordance with the Group’s financial risk management policy as approved by the Board. The Group does not trade in derivative financial instruments for speculative purposes. The Board actively reviews all financial risks and any hedging on a regular basis with updates provided to the Board from independent consultants/banking analysts to keep them fully informed of the current status of the financial markets. Reports providing detailed analysis of any hedging in place are monitored against the Group’s financial risk management policy on a regular basis. 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 derivatives, forward foreign exchange 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. 111 Beach Energy Limited Annual Report 2021 18. Financial risk management (continued) (a) Fair values (continued) The Group’s financial assets and financial liabilities measured and recognised at fair value is set out below: Carrying amount Financial assets Cash and cash equivalents Receivables Lease assets Other Financial liabilities Payables Lease liabilities Interest bearing liabilities Financial assets/ financial liabilities at amortised cost Note 2021 $million 2020 $million 14 14 16 126.7 355.0 72.2 118.8 672.7 267.7 103.0 175.0 545.7 109.9 215.8 58.7 84.8 469.2 282.0 62.1 60.0 404.1 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 2021 and there have been no transfers between the levels of the fair value hierarchy during the year ended 30 June 2021. The Group also has a number of other financial assets and liabilities including cash and cash equivalents, receivables and payables which are recorded at their carrying value which is considered to be a reasonable approximation of their fair value. (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 risk exposure. The Group policy to manage commodity price exposure may include the use of Australian dollar denominated oil options. Changes in fair value of these derivatives are recognised immediately in the profit or loss and other comprehensive income, having regard to whether they are defined as accounting hedges. Foreign exchange risk arises when future commercial transactions and recognised assets and liabilities are denominated in a currency that is not the entity’s functional currency. The Group sells a portion of its products and commits to some contracts in US dollars or NZ dollars. Australian dollar oil option contracts may be used by the Group to manage its foreign currency risk exposure. Any foreign currencies held which are surplus to forecast needs are converted to Australian dollars as required. There were no commodity hedges outstanding at 30 June 2020 or 30 June 2021. 112 Notes to the Financial Statements The Group’s interest rate risk arises from the interest bearing cash held on deposit and its bank loan facility which is 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 2021 $million 2020 $million 126.7 (175.0) (48.3) 109.9 (60.0) 49.9 Sensitivity analysis for all market risks The following table demonstrates the estimated sensitivity to changes in the relevant market parameter, with all variables held constant, on post tax profit and equity, which are the same as the profit impact flows through to equity. These sensitivities should not be used to forecast the future effect of a movement in these market parameters on future cash flows which may be different as a result of the Group commodity hedge book. Impact on post-tax profit and equity A$/$US – 10% increase in Australian/US dollar exchange rate A$/$US – 10% decrease in Australian/US dollar exchange rate US$ oil price – increase of $10/bbl US$ oil price – decrease of $10/bbl Interest rates – increase of 1% Interest rates – decrease of 1% Consolidated 2021 $million 2020 $million (46.4) 56.7 88.5 (90.2) (0.7) (0.2) (52.4) 64.1 109.4 (109.4) 0.2 (0.2) (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. 113 Beach Energy Limited Annual Report 2021 18. Financial risk management (continued) (c) Credit risk (continued) 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 2021 is 0.1% (FY20 0.2%), a loss allowance has been recorded at 30 June 2021 of $0.2 million (FY20 $0.4 million). Ageing of Receivables : Receivables not yet due Receivables past due Considered impaired Total Receivables Consolidated 2021 $million 2020 $million 355.0 0.2 (0.2) 355.0 215.8 0.4 (0.4) 215.8 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 Prudent liquidity risk management implies maintaining sufficient cash and marketable securities, the availability of funding through an adequate amount of committed credit facilities and the ability to close out market positions. The Group aims at maintaining 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 facilities are outlined in Note 16. The Group’s exposure to liquidity risk for each class of financial liabilities is set out below: Less than 1 year 1 to 5 years Greater than 5 years Total 2021 2020 2021 2020 2021 2020 2021 2020 Note $million $million $million $million $million $million $million $million Carrying amount Financial liabilities Payables Lease liabilities Interest bearing liabilities 14 16 263.2 77.0 276.4 26.8 – – 340.2 303.2 2.5 18.3 175.0 195.8 2.9 22.2 60.0 85.1 2.0 7.7 – 9.7 2.7 13.1 – 15.8 267.7 103.0 175.0 545.7 282.0 62.1 60.0 404.1 114 Notes to the Financial Statements 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 2019 Issued during the FY20 financial year Shares issued on vesting/exercise of unlisted performance rights Repayment of employee loans and sale of employee shares Shares purchased on market (Treasury shares), net of tax Issued and fully paid ordinary shares at 30 June 2020 Issued during the FY21 financial year Shares issued on vesting/exercise of unlisted performance rights 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 Number of Shares 2,278,249,104 $million 1,860.6 2,559,073 – – – 1.3 (0.7) 2,280,808,177 1,861.2 525,479 – – – – 0.2 (4.0) 2.1 Issued and fully paid ordinary shares at 30 June 2021 2,281,333,656 1,859.5 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 $5.6 million (FY20: $1.0 million) of Treasury shares were purchased on market. Movement in Treasury shares Balance at 30 June 2019 Shares purchased on market during FY20 Utilisation of Treasury shares on vesting of shares under employee incentive plan Balance at 30 June 2020 Shares purchased on market during FY21 Utilisation of Treasury shares on vesting of rights under executive incentive plan Balance at 30 June 2021 Number – 541,053 (20,728) 520,325 3,523,725 (1,069,650) 2,974,400 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. 115 Beach Energy Limited Annual Report 2021 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 1.5% (FY20 nil). 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 2021 $million 2020 $million 36.5 (5.0) 835.6 867.1 36.0 (5.3) 881.2 911.9 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 (2020 1.0 cent) Interim dividend of 1.0 cent (2020 1.0 cent) Total dividends paid or payable Consolidated 2021 $million 2020 $million 22.8 22.8 45.6 22.8 22.8 45.6 Franking credits available in subsequent financial years based on a tax rate of 30% (2020: 30%) 475.3 354.5 116 Notes to the Financial Statements 22. Subsidiaries Name of Company Beach Energy Limited (1) 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 (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 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) Impress (Cooper Basin) Pty Ltd (1) Springfield Oil and Gas Pty Ltd (1) 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 Kupe Mining (No.1) Limited Beach Energy Resources NZ (Clipper) Limited Beach Energy Resources NZ (Tawhaki) Limited Beach Energy Resources NZ (Tawn) Limited Beach Energy Resources NZ (Wherry No.1) Limited (2) Beach Energy Resources NZ (Wherry No.2) Limited (2) All shares held are ordinary shares, other than Mazeley Ltd which is held by a bearer share. (1) Company in Closed Group in FY20 and FY21 (refer Note 23). (2) Company created and registered during FY21. Place of incorporation 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 New Zealand New Zealand New Zealand New Zealand Percentage of shares held % 2021 % 2020 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 – – 117 Beach Energy Limited Annual Report 2021 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 Transfer to profit distribution reserve Retained earnings/(accumulated losses) at end of the year Closed Group 2021 $million 2020 $million 1,382.3 (867.6) 1,542.9 (989.9) 514.7 11.6 (68.7) 457.6 0.2 (11.8) 446.0 (131.1) 314.9 – 553.0 172.0 (29.1) 695.9 1.1 (21.0) 676.0 (186.7) 489.3 – 314.9 489.3 (238.6) 314.9 – 76.3 72.1 489.3 (800.0) (238.6) 118 Notes to the Financial Statements Consolidated Statement of Financial Position Current assets Cash and cash equivalents Receivables Inventories Other Total current assets Non-current assets Property, plant and equipment Petroleum assets Exploration and evaluation assets Lease assets Intangible Assets Deferred tax assets Other financial assets Total non-current assets Total assets Current liabilities Payables Provisions Current tax liability Lease liabilities Contract liabilities Total current liabilities Non-current liabilities Payables Provisions Lease liabilities Contract 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 2021 $million 2020 $million 113.0 411.2 92.6 71.2 688.0 8.6 3,173.8 213.0 70.1 77.1 – 266.0 3,808.6 4,496.6 209.5 38.5 10.1 76.4 12.0 346.5 408.9 730.6 24.5 3.9 1.3 174.1 1,343.3 1,689.8 2,806.8 1,857.8 872.7 76.3 90.8 329.9 94.5 52.3 567.5 9.6 2,681.6 269.7 45.9 78.8 63.7 244.0 3,393.3 3,960.8 202.3 19.8 83.6 15.3 15.3 336.3 343.4 645.8 32.8 5.9 – 56.7 1,084.6 1,420.9 2,539.9 1,860.6 917.9 (238.6) 2,806.8 2,539.9 119 Beach Energy Limited Annual Report 2021 24. Parent entity financial information Selected financial information of the parent entity, Beach Energy Limited, is set out below: Financial performance Net profit 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 Expenditure Commitments Parent 2021 $million 34.0 – 34.0 963.3 2020 $million 805.7 – 805.7 787.1 2,532.8 2,374.3 626.1 910.0 1,859.5 36.5 835.6 0.6 (1,109.4) 1,622.8 583.0 738.6 1,861.2 36.0 881.3 0.6 (1,143.4) 1,635.7 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 Contingent liabilities and guarantees Parent 2021 $million 2020 $million 1.3 – 3.4 0.2 Details of contingent liabilities for the Company in respect of service agreements, bank guarantees and parent company guarantees are disclosed in Note 27. 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 assets of the controlled entities at the end of the reporting period where this is less than cost. 120 Notes to the Financial Statements 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 Total Subsidiaries Interests in subsidiaries are set out in Note 22. Transactions with other related parties Consolidated 2021 $ 2020 $ 5,401,866 1,381,716 85,447 5,688,692 1,869,206 (36,919) 6,869,029 7,520,979 During the financial year ended 30 June 2021, Beach incurred costs of $847,529 (FY20 $341,956) to Coates Hire Operations Pty Ltd, an entity of which Ryan Stokes is a director, for the hire of equipment on arm’s length commercial terms. Directors fees payable to Mr Davis for the year ended 30 June 2021 of $289,750 (FY20 $305,000) were paid directly to DMAW Lawyers. 26. Acquisitions and disposals The acquisition method of accounting is used to account for all business combinations, including business combinations involving entities or businesses under common control, regardless of whether equity instruments issued or liabilities incurred or assumed at the date of exchange. Where equity instruments are issued in an acquisition, the fair value of the instruments is their published market price as at the date of exchange unless, in rare circumstances, it can be demonstrated that the published price at the date of exchange is an unreliable indicator of fair value and that other evidence and valuation methods provide a more reliable measure of fair value. Transaction costs arising on the issue of equity instruments are recognised directly in equity. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date, irrespective of the extent of any non-controlling interest. Transaction costs incurred in relation to the business combination are expensed as incurred to the Statement of Profit or Loss. The excess of the cost of acquisition over the fair value of the consolidated entity’s share of the identifiable net assets acquired is recorded as goodwill. Asset acquisitions which are not business combinations are accounted for by allocating the purchase consideration, including capitalised transaction costs, against identifiable assets and liabilities acquired, based on their relative fair values determined on acquisition date. Beach executed an asset purchase agreement with Senex Energy in November 2020 to acquire Senex’s Cooper Basin assets for a cash consideration of $87.5 million. The transaction was subject to a number of conditions precedent and completed on 1 March 2021 with an adjustment made to the acquisition price based on cash flows from 1 July 2020 to the completion date. Beach also entered into an asset purchase agreement in January 2021 with Mitsui subsidiaries AWE Petroleum Pty Ltd and AWE (Bass Gas) Pty Ltd to acquire all of its interests in the Bass Basin. These assets include Mitsui’s 35.0% interest in the BassGas Project (comprising the onshore Lang Lang Gas Plant and Yolla gas field), as well as its 40.0% interest in the Trefoil development project and surrounding retention leases. The transaction, the terms of which are confidential, was subject to regulatory approvals and third-party consents and completed on 31 July 2021 with an adjustment made to the acquisition price based on cash flows from 1 July 2020 to the completion date. 121 Beach Energy Limited Annual Report 2021 26. Acquisitions and disposals (continued) Both acquisitions have been accounted for as asset acquisitions as they meet the requirements of the optional concentration test under AASB 3 Business Combinations. Details of the combined purchase consideration and purchase price allocation to net identifiable assets acquired for both acquisitions are as follows: Purchase consideration Transaction costs Total purchase consideration Fair Value of assets acquired Assets and liabilities held at acquisition date: – Receivables – Inventory – Petroleum assets – Exploration and evaluation assets – Current payables – Restoration provision – Other non-current provisions Net assets acquired Purchase consideration Add amount to be received on completion Less accrued transactions costs Net cash outflow on acquisition $million 71.7 4.6 76.3 8.1 5.2 117.9 48.8 (5.4) (98.1) (0.2) 76.3 76.3 11.6 (3.7) 84.2 In the prior financial year, a gain on sale of joint operations interests was $8.9 million was recognised in relation to: – The sale of Beach’s interest in ex PEL 103 (Innamincka Dome) with Beach realising a gain of approximately $5.9 million from the removal of all associated liabilities; – The sale of 17% interest in production licences L11 and L22 (Beharra Springs), exploration permit EP 320 and pipeline licence PL 18 in the Perth Basin to Mitsui to align ownership interests at 50:50 resulted to a gain on sale of $2.6 million. – An adjustment to the gain on sale of 40% of Beach’s Victorian Otway assets to O.G. Energy Holdings Ltd. of $0.4 million. In the prior financial year, activities for Beach Petroleum (Tanzania) Limited effectively ceased resulting in the release of a cumulative gain of $8.7 million on the historic translation of this entity from other comprehensive income to the statement of profit or loss in FY20. 122 Notes to the Financial Statements Other information Additional information required to be disclosed under Australian Accounting Standards. 27. 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 2021 under the service agreements for the executive officers is $2,083,910 (FY20 $1,688,879). Bank guarantees As at 30 June 2021, Beach has been provided with a $75 million letter of credit facility, of which $73 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. 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 costs which are not included in our best estimate and the associated provision recorded at 30 June 2021. In April 2021 the Federal Government issued a draft Offshore Petroleum and Greenhouse Gas Storage Amendment (Titles Administration and Other Measures) Bill aiming to strengthen and clarify Australia’s offshore oil and gas regulatory framework. The Bill is currently subject to ongoing consultation with industry. The Bill includes amendments relating to ‘call back’ on previous titleholders to decommission and remediate the environment where the current titleholder is unable to do so (also known as trailing liability). If passed, these provisions may give rise to potential trailing liabilities for any petroleum titles issued under Commonwealth offshore petroleum legislation that Beach has divested. 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. The final form of the Bill is not expected to be finalised until FY22 and, based on the assumption that the final legislation will not have retrospective application, it is not expected to materially impact the financial position or performance of the Group at 30 June 2021. 123 Beach Energy Limited Annual Report 2021 27. Contingent liabilities (continued) 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. 28. 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 Other services 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 29. Subsequent events Consolidated 2021 $000 2020 $000 801 35 74 225 1,135 135 20 155 14 14 801 35 125 35 996 135 20 155 19 19 1,304 1,170 The acquisition by Beach of Mitsui’s 35.0% interest in the BassGas Project (comprising the onshore Lang Lang Gas Plant and Yolla gas field), as well as its 40.0% interest in the Trefoil development project and surrounding retention lease completed in July 2021 with an adjustment made to the acquisition price based on cash flows from the effective date of 1 July 2020 to the completion date. The Group has received a favourable arbitral outcome in relation to a contractual dispute under one of its long term gas sales agreements in New Zealand regarding the allocation of carbon emission obligations between the parties. A one-off cash payment of circa NZ$42m (plus interest) will be received in reimbursement of costs incurred to satisfy the emission obligations under the gas sales agreement during the period of the dispute. The details of the dispute are confidential. Other than the matters described above, there has not arisen in the interval between 30 June 2021 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. 124 Notes to the Financial Statements 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) and its subsidiaries (collectively the Group), which comprises the consolidated statement of financial position as at 30 June 2021, the consolidated statement of profit or loss and comprehensive income, consolidated statement of changes in equity and consolidated statement of cash flows for the year then ended, notes to the financial statements, including a summary of significant accounting policies, and the directors’ declaration. In our opinion, the accompanying financial report of the Group is in accordance with the Corporations Act 2001, including: a. Giving a true and fair view of the consolidated financial position of the Group as at 30 June 2021 and of its consolidated financial performance for the year ended on that date; and b. Complying with Australian Accounting Standards and the Corporations Regulations 2001. Basis for opinion We conducted our audit in accordance with Australian Auditing Standards. Our responsibilities under those standards are further described in the Auditor’s responsibilities for the audit of the financial report section of our report. We are independent of the Group in accordance with the auditor independence requirements of the Corporations Act 2001 and the ethical requirements of the Accounting Professional and Ethical Standards Board’s APES 110 Code of Ethics for Professional Accountants (including Independence Standards) (the Code) that are relevant to our audit of the financial report in Australia. We have also fulfilled our other ethical responsibilities in accordance with the Code. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion. Key audit matters Key audit matters are those matters that, in our professional judgment, were of most significance in our audit of the financial report of the current year. These matters were addressed in the context of our audit of the financial report as a whole, and in forming our opinion thereon, but we do not provide a separate opinion on these matters. For each matter below, our description of how our audit addressed the matter is provided in that context. We have fulfilled the responsibilities described in the Auditor’s responsibilities for the audit of the financial report section of our report, including in relation to these matters. Accordingly, our audit included the performance of procedures designed to respond to our assessment of the risks of material misstatement of the financial report. The results of our audit procedures, including the procedures performed to address the matters below, provide the basis for our audit opinion on the accompanying financial report. A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 125 Beach Energy Limited Annual Report 2021 Independent Auditor’s Report Page 2 Carrying value of petroleum assets Why significant How our audit addressed the key audit matter At 30 June 2021 the Group had petroleum assets of $3,431.6 million. Australian Accounting Standards require the Group to assess throughout the 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. The Group identified impairment indicators in respect of certain petroleum asset cash generating units (‘CGUs’). Impairment testing was undertaken which resulted in an impairment charge of $35.3 million being recorded during the year, as set out in Note 9 of the financial report. 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. Where impairment indicators are identified, 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 such as, discount rates, foreign exchange rate, and commodity prices used in the Group’s impairment assessment are set out in the Financial Report in Note 9. As a result, 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. In completing our audit procedures, we: • Assessed the Group’s definition of CGU in accordance with Australian Accounting Standards. • Evaluated the assumptions, methodologies and conclusions used by the Group in assessing for indicators of impairment and impairment reversal, in particular, those relating to the forecast cash flows and inputs used to formulate them. This included assessing, in conjunction with our valuation specialists, the discount rates, foreign exchange rates and commodity prices with reference to market prices (where available), market research, market practice, market indices, broker consensus and historical performance. • Used the work of the Group’s internal and external experts with respect to the hydrocarbon reserve assumptions used in the cash flow forecasts. This included understanding the reserve estimation processes carried out, and assessing the qualifications, competence and objectivity of the Group’s experts, the scope and appropriateness of their work. • Analysed forecast cost assumptions against historical performance and the latest approved budgets and forecasts. • Considered the Group’s market capitalisation. • Considered the carrying value of producing assets against recent comparable market transactions and the market value of comparable companies, where available. • Assessed the adequacy of the disclosures in Note 9 and basis of preparation of the financial report Impairment assessment of capitalised exploration and evaluation expenditure Why significant How our audit addressed the key audit matter At 30 June 2021 the Group had exploration and evaluation assets of $334.8 million. For exploration and evaluation assets, in completing our audit procedures, we: The carrying value of exploration and evaluation assets is subjective based on the Group’s ability and intention, to continue to explore the assets. The carrying value may also be impacted by the results of exploration work indicating that the oil and gas resources may not be commercially viable for extraction. The Group is required to assess whether any indicators of impairment are present. Key assumptions, judgements and estimates used in the impairment indicator assessment can lead to significant changes in respect to whether economic quantities of hydrocarbons can be commercialised or whether further exploration and evaluation work is underway or planned to support the continued carry forward of capitalised costs. The Group identified impairment indicators in respect of certain exploration and evaluation assets. The impairment testing of those assets resulted in an impairment charge of $81.7 million being recorded during the year, as set out in Note 10 of the financial report. • Assessed whether any impairment indicators, as set out in AASB 6 Exploration for and Evaluation of Mineral Resources, were present, and assessed the conclusions reached by management. • Assessed the Group’s definition of area of interest in accordance with Australian Accounting Standards. • Considered the Group’s right to explore in the relevant exploration area which included obtaining and assessing supporting documentation such as license agreements and correspondence with relevant government agencies. • Considered the Groups intention to carry out significant exploration and evaluation activities in relevant exploration areas or plans to transfer the assets to petroleum assets. This included the assessment of the Group’s forecasts with comparison to approved budgets and enquiries with senior exploration management and directors as to the intentions and strategy of the Group. A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 126 Page 3 Why significant How our audit addr essed t he key audit mat t er As a result, we considered the impairment testing of the Group’s exploration and evaluat ion asset s and the related disclosures in the financial report to be a key audit matter • Assessed the carrying value of explorat ion and evaluat ion asset s where recent exploration activity, in a given licensed area, provided negat ive indicators as to the recoverability of amounts capitalised. • Considered the commercial viability of results relat ing to the exploration and evaluation activities carried out in the relevant licensed areas. • Assessed the Group’s ability t o finance any planned future exploration and evaluation activity. • Assessed the adequacy of the disclosures in Note 10 of the financial report. Provisionally priced oil revenue Why significant How our audit addr essed t he key audit mat t er At 30 June 2021 the Group recorded $110.9 million of provisionally priced oil revenue (30 June 2020: $89.1 million), which represent s a significant port ion (18%) of total annual oil revenue (30 June 2020: 11%). In accordance with cont ractual terms within the Crude Oil sale and Purchase Agreement (‘COSPA’), risk and t itle of oil produced in the Cooper Basin is t ransferred to the South Aust ralian Cooper Basin Joint Venture (‘SACBJV’), when the oil reaches the Moomba processing facility. The supply of oil to the Moomba processing facility is the point the Group satisfies the performance obligat ion to the SACBJV in respect of the supply of oil Revenue is calculated using forecast oil price est imates when title has passed with actual invoices not raised until the oil has shipped from Port Bonyt hon. Given the complexity in calculating the volume of oil supplied and judgement in the application of the estimated transaction price, there can be significant variat ions in the final revenue value recorded on invoicing. As such, this was considered a key audit matter. Disclosure regarding this matter can be found in Note 2 of the Financial Report . In completing our audit procedures, we: • Assessed the point and recognition of revenue with reference to executed contracts bet ween the parties and the requirements of Australian Account ing Standards. • Obtained directly from the SACBJV an independent confirmation of barrels of oil received at the Moomba processing facility, but not yet shipped via Port Bonyt hon. • For all provisionally priced revenue barrels sold, we assessed the est imated sales price applied by the Group to forward commodity price assumptions together with estimates of quality premiums and exchange rates for the period in which set tlement is likely to occur with reference to contractual arrangement s and Brent oil price futures. • Selected shipment s which occurred close to the period end and assessed whether revenue was recorded in the correct period. • Selected and examined evidence of subsequent cash receipt. Informat ion ot her t han t he financial report and audit or’s report t hereon The directors are responsible for the other information. The other information comprises the information included in the Company’s 2021 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. In connection wit h 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. A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislat ion 127 Beach Energy Limited Annual Report 2021 Independent Auditor’s Report Page 4 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 Group’s ability to continue as a going concern, disclosing, as applicable, matters relating to going concern and using the going concern basis of accounting unless the directors either intend to liquidate the Group or to cease operations, or have no realistic alternative but to do so. Auditor’s responsibilities for the audit of the financial report Our objectives are to obtain reasonable assurance about whether the financial report as a whole is free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with the Australian Auditing Standards will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of this financial report. As part of an audit in accordance with the Australian Auditing Standards, we exercise professional judgment and maintain professional scepticism throughout the audit. We also: ► Identify and assess the risks of material misstatement of the financial report, whether due to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. ► Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Group’s internal control. ► Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by the directors. ► Conclude on the appropriateness of the directors’ use of the going concern basis of accounting and, based on the audit evidence obtained, whether a material uncertainty exists related to events or conditions that may cast significant doubt on the Group’s ability to continue as a going concern. If we conclude that a material uncertainty exists, we are required to draw attention in our auditor’s report to the related disclosures in the financial report or, if such disclosures are inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up to the date of our auditor’s report. However, future events or conditions may cause the Group to cease to continue as a going concern. A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 128 Page 5 ► 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. ► Obtain sufficient appropriate audit evidence regarding the financial information of the entities or business activities within the Group to express an opinion on the financial report. We are responsible for the direction, supervision and performance of the Group audit. We remain solely responsible for our audit opinion. We communicate with the directors regarding, among other matters, the planned scope and timing of the audit and significant audit findings, including any significant deficiencies in internal control that we identify during our audit. We also provide the directors with a statement that we have complied with relevant ethical requirements regarding independence, and to communicate with them all relationships and other matters that may reasonably be thought to bear on our independence, and where applicable, actions taken to eliminate threats or safeguards applied. From the matters communicated to the directors, we determine those matters that were of most significance in the audit of the financial report of the current year and are therefore the key audit matters. We describe these matters in our auditor’s report unless law or regulation precludes public disclosure about the matter or when, in extremely rare circumstances, we determine that a matter should not be communicated in our report because the adverse consequences of doing so would reasonably be expected to outweigh the public interest benefits of such communication. Report on the audit of the Remuneration Report Opinion on the Remuneration Report We have audited the Remuneration Report included in pages 62 to 78 of the directors’ report for the year ended 30 June 2021. In our opinion, the Remuneration Report of Beach Energy Limited for the year ended 30 June 2021, complies with section 300A of the Corporations Act 2001. Responsibilities The directors of the Company are responsible for the preparation and presentation of the Remuneration Report in accordance with section 300A of the Corporations Act 2001. Our responsibility is to express an opinion on the Remuneration Report, based on our audit conducted in accordance with Australian Auditing Standards. Ernst & Young Anthony Jones Partner Adelaide 16 August 2021 A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 129 Beach Energy Limited Annual Report 2021 Glossary A$ or $ 1C 2C 3C 3D 1P 2P 3P AASB AGM AOI ASX ATP Alinta Energy BassGas Project bbl Bcf Beach Beharra Springs boe Board Bridgeport CAGR CCS CGU Company Cooper Energy Cooper Basin CBJV (Cooper Basin JV) Australian dollars Contingent resource low estimate(1) Contingent resource best estimate(1) Contingent resource high estimate(1) Three dimensional Proved reserve estimate(1) Proved and probable reserve estimate(1) Proved, probable and possible reserve estimate(1) Australian Accounting Standards Board Annual General Meeting Area of interest Australian Securities Exchange Authority To Prospect (QLD) Alinta Energy Retail Sales Pty Ltd The BassGas Project (Beach 53.75% and operator, MEPAU 35%, 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 50.25% operated interest in licenses TR/L2, TR/L4 and TR/L5. On 31 July 2021 Beach completed its acquisition of MEPAU’s 35% participating interest in T/ L1 and 40% participating interest in TR/L2, TR/L4 and T/RL5, Beach will then hold a 88.75% interest in the BassGas Project and 90.25% interest in TR/L2, TR/L4 and TR/L5 Barrels Billion cubic feet Beach Energy Limited Beach 50% and operator, MEPAU 50%. Consists of the Beharra Springs, Redback Terrace and Tarantula gas fields and the Beharra Springs gas processing facilities 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 Bridgeport (Cooper Basin) Pty Ltd Compounded annual growth rate Carbon Capture and Storage Cash generating unit Beach and its subsidiaries Cooper Energy Ltd Includes both Cooper and Eromanga Basins The various joint venture interests owned by Beach’s wholly owned subsidiaries Delhi and Beach Energy (Operations) in the SACB JVs and SWQ JVs DBNGP Delhi DTA EBITDA EIP EP EPS Ex PEL 91 Ex PEL 92 Ex PEL 104/111 Ex PEL 106 Ex PEL 513 Ex PEL 632 FEED FID Free cash flow FY21 Genesis Group GSA GJ HBWS H1 FY21 IFRS JV kbbl kboe kbopd km KMP KPI kt Kupe LNG LPG LTI Dampier to Bunbury Natural Gas Pipeline Delhi Petroleum Pty Ltd Deferred tax assets Earnings before interest, tax, depreciation and amortisation Executive Incentive Plan Exploration Permit (NT) Earnings per share PRLs 151 to 172 and various production licences PRLs 85 to 104 and various production licences PRLs 136 to 150 and various production licences PRLs 129 and 130 and various production licences PRLs 191 and 206 and various production licences PRLs 131 to 134 and various production licences Front-End Engineering Design Final Investment Decision Operating cash flow less investing cash flow (excluding acquisitions and divestitures) Financial year 2021 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) First half year period of FY21 International Financial Reporting Standards Joint Venture 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%. Consists of offshore Kupe gas field in the Taranaki Basin, the Kupe offshore platform, Kupe gas plant and associated infrastructure Liquefied natural gas Liquefied petroleum gas Long term incentive (1) Complete definitions for Reserves and contingent resources are contained within “Petroleum Resources Management Systems (revised June 2018)” better known as PRMS 2018. 130 SGH SPE STI Seven Group Holdings Limited Society of Petroleum Engineers Short Term Incentive SWQ JVs South West Queensland Joint Ventures South West Queensland Joint Ventures Includes the SWQ Gas Unit and exploration and oil production licences – various equity interests (Beach 30–52.2%) Tcf TFR TJ TRIFR TSR Trillion cubic feet Total Fixed Remuneration Terajoule Total recordable injury frequency rate Total shareholder return Udacha Block PRL 26 US$ Waitsia United States $ Beach 50%, MEPAU 50% and operator. The project consists of the Waitsia Gas Project, an interest in the Xyris production facility and other in-field pipelines MEPAU Mitsui MMbbl MMboe MMscf MMscfd Net Gearing NPAT NZ NZOG O.G. Energy OGP OMV Origin Otway Sale PACE PCP PEL PEP Perth Basin PL PPL PJ Prize PRL PRMS PRRT Q1 FY21 ROC SACB JVs 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 The ratio of net debt/(cash) to the sum of net debt/(cash) and total book equity Net profit after tax New Zealand New Zealand Oil & Gas Limited and its subsidiaries 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 OMV Group and its subsidiaries Origin Energy Limited and its subsidiaries Sale of 40% of Beach’s Victorian Otway interests to O.G. Energy (for additional information please refer to ASX announcement REF: #047/18) The South Australian Plan for Accelerating Exploration gas grant scheme Prior corresponding period Petroleum Exploration Licence (SA) Petroleum Exploration Permit (Victoria and NZ) Includes Beach’s assets Waitsia and Beharra Springs Petroleum Lease (QLD) Petroleum Production Licence (SA) Petajoule Prize Petroleum Licence Petroleum Retention Licence (SA) Petroleum Resources Management System Petroleum Resource Rent Tax First quarter of FY21 Return on capital South Australian Cooper Basin Joint Ventures South Australian Cooper Basin Joint Ventures The Fixed Factor Area (Beach 33.4%, Santos 66.6%) and the Patchawarra East Block (Beach 27.68%, Santos 72.32%) Santos SAWA Senex Santos Limited and its subsidiaries South Australia Western Australia reporting segment Senex Energy Limited 131 Beach Energy Limited Annual Report 2021 Schedule of Tenements For the year ended 30 June 2021 Cooper/Eromanga – Queensland Subsidiary Company Tenement 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% DLS 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) ex ATP 299 (Tintaburra Block) (9) Circumpacific ATP 940 Cooper/Eromanga – South Australia Subsidiary Company Tenement Impress (CB) PPL 203 (Acrasia Oil Field) BPT BPT Impress (CB) Impress (CB) PPL 204 (Sellicks Oil Field) PPL 205 (Christies Oil Field) PPL 207 (Worrior Field) PPL 208 (Derrilyn West Field) (10) Impress (CB) PPL 209 (Harpoono Field) BPT Impress (CB) BPT 40% DLS 30% GAOG 30% Impress (CB) Impress (CB) Impress (CB) Impress (CB) Impress (CB) BPT PPL 210 (Aldinga Oil Field) PPL 211 (Reg Sprigg West Field) (18) PPL 212 (Kiana Oil Field) PPL 213 (Mirage Field) PPL 214 (Ventura Field) PPL 215 (Toparoa Field) (10) PPL 217 (Arwon West Field) PPL 218 (Arwon East Field) PPL 220 (Callawonga Oil Field) Impress (CB) PPL 221 (Padulla Field) 132 % 38.5% 47.5% 45% 52.2% 30% 30% 38.8% 40% 39.9375% BPT BPT 50% GAOG 50% PPL 224 (Parsons Oil Field) PPL 239 (Middleton/Brownlow Fields) Impress (CB) 85% Springfield 15% PPL 240 (Snatcher Oil Field) Impress (CB) PPL 241 (Vintage Crop Field) Impress (CB) 85% Springfield 15% PPL 242 (Growler Oil Field) Impress (CB) 85% Springfield 15% PPL 243 (Mustang Oil Field) BPT BPT BPT BPT BPT BPT 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) Impress (CB) PPL 251 (Burruna Field) 40% 100% % 100% 75% 75% 70% 100% 100% 50% 100% 100% 100% 100% 100% 100% 100% 75% 100% BPT 40% GAOG 60% BPT 40% GAOG 60% BPT 40% GAOG 60% BPT 40% GAOG 60% BPT 50% GAOG 50% PPL 253 (Bauer/Bauer-North/ Chiton/Arno Oil Fields) PPL 254 (Congony/ Kalladeina Oil Fields) PPL 255 (Hanson/Snelling Oil Fields) PPL 256 (Sceale Oil Field) PPL 257 (Canunda/Coolawang Fields) Impress (CB) 85% Springfield 15% PPL 258 (Spitfire Oil Field) BPT 40% GAOG 60% BPT 40% GAOG 60% BPT 40% GAOG 60% PPL 260 (Stunsail Oil Field) PPL 261 (Pennington Oil Field) PPL 262 (Balgowan Oil Field) Impress (CB) 85% Springfield 15% PPL 263 (Martlett North Oil Field) (11) Impress (CB) 85% Springfield 15% PPL 264 (Martlett Oil Field) Impress (CB) 85% Springfield 15% PPL 265 (Marauder Oil Field) Impress (CB) 85% Springfield 15% PPL 266 (Breguet Oil Field) Impress (CB) 57% Acer 43% PPL 268 (Vanessa Gas Field) % 75% 100% 100% 100% 100% 100% 75% 75% 75% 75% 75% 75% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% Subsidiary Company Tenement % Subsidiary Company Tenement Impress (CB) PPL 270 (Gemba Field) Impress (CB) 85% Springfield 15% PRL 15 (Growler Block) Impress (CB) PRL 16 (Dunoon-2) BPT 25% DLS Gas 30% GAOG 45% BPT Impress (CB) Impress (CB) PRL 26 (Udacha Unit) PRLs 35, 37, 38, 41, 43-45, 48, 49 (ex PEL 218 Permian) PRL 73 (ex PEL 90C) PRLs 76 to 77 (ex PEL 102) Impress (CB) PRLs 78 to 84 (ex PEL 113) BPT Impress (CB) Impress (CB) Impress (CB) BPT 50% GAOG 50% GAOG PRLs 85 to 104 (ex PEL 92) PRLs 105, 106, 116, 117 (ex PEL 115) PRLs 108 to 110 (ex PEL 105) PRLs 120 and 128 (ex PEL 514) PRLs 129 and 130 (ex PEL 106) PRLs 131 to 134 (ex PEL 632) Impress (CB) 57% Acer 43% PRL 135 (Vanessa Gas Field) (12) Impress (CB) 85% Springfield 15% PRLs 136 to 150 (ex PEL 104 and PEL 111) (13) BPT 40% GAOG 60% Acer BPT 40% DLS 20% GAOG 40% Impress (CB) DLS (513) PRLs 151 to 172 (ex PEL 91) PRLs 173 to 174 (ex PEL 101) PRLs 175 to 179 (ex PEL 107) PRLs 183 to 190 (ex PEL 110) (14) PRLs 191 to 206 (ex PEL 513) Impress (CB) Impress (CB) Impress (CB) Impress (CB) 100% 100% 100% 100% 100% PRLs 207 to 209 (ex PEL 100) (15) PRLs 210 to 220 (ex PEL 637) PRLs 221 to 230 (ex PEL 638) PRLs 231 to 233 and 237 (ex PEL 93) (16) Impress (CB) 57% Acer 43% PRLs 238 to 244 (ex PEL 182) PRLs 245 to 246 (ex PEL 90k) PEL 94 (17) PEL 95 PEL 182 PEL 516 PEL 570 PEL 630 PEL 639 GSEL 634 (ex PEL 92) GSEL 645 (ex Udacha Unit) GSEL 646 (ex PEL 106) GSEL 648 (ex PEL 91) GSEL 653 (ex PEL 107) 100% Impress (CB) 100% 100% 75% BPT 50% Impress (BCB) 15% BPT Impress (CB) 57% Acer 43% 100% Impress (CB) Ambassador BPT Impress (CB) BPT BPT 25% DLS Gas 30% GAOG 45% BPT 50% GAOG 50% BPT 40% GAOG 60% BPT 40% DLS 20% GAOG 40% Delhi 12.86% BE(OP)L 7.902% Delhi 17.14% BE(OP)L 10.536% Delhi 20.21% BE(OP)L 13.19% Delhi 20.21% BE(OP)L 13.19% 100% 100% 100% 40% 100% 100% 100% 100% 100% 80% 40% % 55% 100% 100% 70% 100% 100% 65% 50% 100% 100% 47.5% 50% 100% 75% 100% 100% 100% 100% Reg Sprigg West Unit 20.759% Patchawarra East (19) 27.676% Fixed Factor Agreement (20) 33.4% SA Unit 33.4% 133 Beach Energy Limited Annual Report 2021 Schedule of Tenements Otway – South Australia Subsidiary Company Tenement 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 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 Tenement BE(OP)L BE(OP)L BE(OP)L Vic/L1(V) Vic/P42(V) Vic/P007192(V) (21) (24) 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 Subsidiary Company Tenement BPT WA-80-R % 9.7637% Bonaparte Basin – Western Australia Subsidiary Company Tenement BE(OP)L BE(B)PL BE(O)PL BE(B)PL WA-454-P WA-6-R WA-545-P WA-548-P 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% T/30P T/L2 (Thylacine) T/L3 (Thylacine South) 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) (21) (22) T/RL2 (21) (23) T/RL4 (21) (23) T/RL5 (21) (23) % 50% 5.75% 10% 5.75% % 100% 60% 60% % 88.75% 90.25% 90.25% 90.25% % 70% 70% 100% 100% 100% 100% 100% 70% 100% 70% % 10% 10% 50% % 60% 60% 60% % 60% 60% 60% 134 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(OP)L BE(B)PL BE(B)PL NT/P82 (21) NT/P88 NT/RL1 Taranaki Basin – New Zealand Subsidiary Company Tenement BERNZKL Kupe Mining No.1 Ltd PML 38146 (Kupe) % 50% 50% 50% % 0% 5.75% 5.75% % 50% (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. (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. (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. (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. (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. (7) The Wareena Block consists of ATP 1189 ex ATP 259 (Wareena) and PLs 113, 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. (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, 293, 294, 295, 298, PLA 1027, PLA 1029. (10) Derrilyn Unitisation Agreement for PPL 206, PPL 208 and PPL 215 – Impress (CB) acquisition of 35% interest subject to regulatory approval. (11) PPL 265 – Impress (CB) acquisition of 60% interest subject to regulatory approval. (12) PRL 135 (Vanessa Gasfield) – Impress (CB) acquisition of 57% interest subject to regulatory approval. (13) PRLs 136 to 150 (ex PEL 104 and PEL 111) – Impress (CB) further acquisition of 60% subject to regulatory approval. (14) PRLs 183 to 190 (ex PEL 110) – Impress (CB) acquisition of 80% interest subject to regulatory approval. (15) PRLs 207 to 209 (ex PEL 100) – Impress (CB) acquisition of 55% subject to regulatory approval. (16) PRLs 231 to 233 and 237 (ex PEL 93) – Impress (CB) acquisition of 70% subject to regulatory approval, and in relation to PRL 237 also subject to completion. (17) PEL 94 – Impress (CB) acquisition of 15% subject to regulatory approval. (18) Reg Sprigg West Unitisation Agreement for well consists of PPL 211 (Impress CB) and PPL 94 (Patchawarra East). (19) 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. (20) 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. (21) Transfer of interest subject to Government approvals. (22) BE(OP)L acquired an additional 35.00% interest in T/L1 from MEPAU which completed on 31 July 2021. (23) BE(OP)L acquired an additional 40.00% interest in T/RL2, T/RL4, T/RL5 from MEPAU which completed on 31 July 2021. (24) BE(OP)L has transferred a 40.00% interest to OGOG with an effective date of 9 July 2020. 135 Beach Energy Limited Annual Report 2021 Schedule of Tenements Subsidiary Companies Acer Ambassador ADE BPT BE(Op)L BE(B)PL BE(Ot)L BE(PB)PL BERNZ(K)L BE(BG)L BE(O)PL Circumpacific Delhi DLS (513) DLS DLS Gas GAOG Impress (CB) Maw Springfield Acer Energy Pty Ltd Ambassador Exploration Pty Ltd Adelaide Energy Pty Ltd Beach Energy Limited Beach Energy (Operations) Limited Beach Energy (Bonaparte) Pty Limited Beach Energy (Otway) Limited Beach Energy (Perth Basin) Pty Limited Beach Energy Resources NZ (Kupe) Limited Beach Energy (Bass Gas) Limited Beach Energy (Offshore) Pty Ltd Circumpacific Energy (Australia) Pty Ltd Delhi Petroleum Pty Ltd Drillsearch (513) Pty Ltd Drillsearch Energy Ltd Drillsearch Gas Pty Ltd Great Artesian Oil & Gas Pty Ltd Impress (Cooper Basin) Pty Ltd Mawson Petroleum Pty Ltd Springfield Oil and Gas Pty Ltd Tenements Acquired VIC/P007192(V), PEL 680, Impress (CB) tenements, WA-545-P, WA-548-P, NT/P88 Tenements Divested PEP 57080, PEP 38264, PEP 52717, PEP 50119, PRL 13, NT/P84, NT/P85, WA-359-P, T/RL3, Wareena PLs 136 Shareholder information Share details – Distribution as at 2 August 2021 Range 1 – 1000 1,001 – 5,000 5,001 – 10,000 10,001 – 100,000 100,001 Over Rounding Rounding Total Unmarketable Parcels Minimum $ 500.00 parcel at $ 1.2350 per unit Total holders Units % Units 9,403 14,339 6,938 9,697 693 4,874,332 39,685,065 53,020,211 270,852,880 1,912,901,168 0.21 1.74 2.32 11.87 83.85 0.01 41,070 2,281,333,656 100.00 Minimum Parcel Size 405 Holders 3,728 Units 709,868 Substantial shareholders as disclosed by notices received by Beach as at 2 August 2021 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 2021 Rank Name Units % Units 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 HSBC CUSTODY NOMINEES (AUSTRALIA) LIMITED NETWORK INVESTMENT HOLDINGS PTY LTD NETWORK INVESTMENT HOLDINGS PTY LTD J P MORGAN NOMINEES AUSTRALIA PTY LIMITED CITICORP NOMINEES PTY LIMITED BNP PARIBAS NOMS PTY LTDNATIONAL NOMINEES LIMITED NETWORK INVESTMENT HOLDINGS PTY LTD BNP PARIBAS NOMS PTY LTD NETWORK INVESTMENT HOLDINGS PTY LTD MR ROBERT LEE PETERSEN NETWORK INVESTMENT HOLDINGS PTY LTD VASTE DEVELOPMENTS PTY LIMITED BNP PARIBAS NOMINEES PTY LTD HUB24 CUSTODIAL SERV LTD AYERSLAND PTY LTD MR KENNETH JOSEPH HALL NETWEALTH INVESTMENTS LIMITED BNP PARIBAS NOMINEES PTY LTD BNP PARIBAS NOMINEES PTY LTD SIX SIS LTD CITICORP NOMINEES PTY LIMITED Totals: Top 20 holders of FULLY PAID ORDINARY SHARES (Total) Total Remaining Holders Balance 514,761,487 333,511,087 250,000,000 237,927,855 146,329,333 51,928,310 40,809,734 34,127,698 20,410,384 18,742,950 15,238,155 14,172,317 8,000,000 6,787,218 6,115,110 6,000,000 5,635,812 5,141,833 5,060,086 4,988,238 1,725,687,607 555,646,049 22.56 14.62 10.96 10.43 6.41 2.28 1.79 1.50 0.89 0.82 0.67 0.62 0.35 0.30 0.27 0.26 0.25 0.23 0.22 0.22 75.64 24.36 137 Beach Energy Limited Annual Report 2021 Corporate Information Annual General Meeting For information about the Annual General Meeting, please visit: beachenergy.com.au/agm Corporate Directory Chairman Glenn Stuart Davis LLB, BEc, FAICD Independent non-executive Deputy Chairman Colin David Beckett AO FIEA, MICE, GAICD Independent non-executive Directors Philip James Bainbridge BSc (Hons) (Mechanical Engineering), MAICD Independent non-executive Matthew Kay BEc, MBA, FCPA, GAICD Managing Director Sally-Anne Layman B Eng (Mining) Hon, B Com, CPA, MAICD Independent non-executive Peter Stanley Moore PhD, BSc (Hons), MBA, GAICD Independent non-executive Joycelyn Cheryl Morton BEc, FCA, FCPA, FIPA, FCIS, FAICD Independent non-executive Richard Joseph Richards BComs/Law (Hons), LLM, MAppFin Non-executive Ryan Kerry Stokes AO BComm, FAIM Non-executive Margaret Helen Hall Alternate (non-executive) Director for Ryan Kerry Stokes B.Eng (Met) Hons, MIEAust, GAICD, SPE Company Secretary Daniel Murnane BA/LLB 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: (08) 8236 2300 Facsimile: (08) 8236 2305 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 beachenergy.com.au 2021 Annual Report