2 0 2 0 A n n u a l R e p o r t Investing for increased gas supply Annual Report 2020 Cooper Energy We energise the lives of thousands of Australians everyday by finding, developing and commercialising oil and gas. We do this with care and strive to provide attractive returns for our shareholders; good commercial outcomes for our customers; and benefits for our stakeholders. Cooper Energy Limited ABN 93 096 170 295 Cover: Athena Gas Plant. Information on descriptions of the company and years, abbreviations and industry terms. The terms “the company” and “Cooper Energy” are used in the report to refer to Cooper Energy Limited and/or its subsidiaries. The terms “2020”, “FY20” and the “2020 financial year” refer to the 12 months ended 30 June 2020 unless otherwise stated. Likewise references to 2019, FY19 or 2021, FY21 refer to the 12 months ending 30 June of that year. This Report uses terms and abbreviations relevant to the Group, its accounts and the petroleum industry. Information on abbreviations and terms, rounding and reserves and resources reporting is provided on page 128. Our values and what they mean. We have chosen to be a values-driven business. We strive to think, decide and act at all times in accordance with our seven core values: Care: prioritising safety, health, the environment and community Integrity: striving to be consistent; staying true to our values and being accountable for our actions Fairness and Respect: valuing diversity and difference; acting without prejudice; and communicating with courtesy Transparency: being honest; addressing problems; and being clear with our communications Collaboration: sharing ideas and knowledge; encouraging cooperation; listening to our stakeholders; and building long term relationships Awareness: taking account of all identified key issues in our decisions and considering future impacts Commitment: staying focused on core objectives; making pragmatic, quality technical and commercial decisions; and being decisive with the courage of our convictions 1 Our business We generate revenue from the discovery, commercialisation and sale of gas to south-east Australia and from cash generating Cooper Basin oil production. We have purpose-built our portfolio to provide attractive returns for our shareholders and good commercial outcomes for our customers by selecting assets that: • possess superior competitiveness for the supply of gas to market; • are in production or expected to be ready for a development decision within 5 years; and • are value accretive. FY20 Production 1.56 MMboe Proved and Probable Reserves 49.9 MMboe at 30 June 2020 Contingent Resources (2C) 34.9 MMboe at 30 June 2020 0.20 0.34 1.6 9.5 0.8 8.5 1.02 38.8 25.5 Otway gas Sole gas Cooper Basin oil Otway Basin gas Otway Basin gas Gippsland Basin gas and gas liquids Gippsland Basin gas and gas liquids Cooper Basin oil Cooper Basin oil Other key statistics: As at 30 June 2020 Market capitalisation: Net debt: Issued shares: Shareholders: $608 million $97.8 million 1,621.6 million 8,094 Employees and contractors: 107.4 full time equivalent 2 1. Offshore Otway Basin: 2. Gippsland Basin: Gas production and exploration • Casino Henry Netherby gas production and development Offshore gas production and exploration • Sole gas field • Annie gas field • Gas exploration • Manta gas and liquids resource • Exploration permits Darwin 5 Brisbane Perth Office Adelaide Office Sydney 4 3 1 Melbourne 2 Hobart 3. Athena Gas Plant: Gas processing for offshore Otway Basin • Being commissioned for commencement of operations in September Quarter 2021 4. Onshore Otway Basin: 5. Cooper Basin: Gas exploration • Gas exploration Onshore oil production • Western flank oil production and exploration 3 Key results Financial • Sales revenue up 3% to $78.1 million due to higher revenue from gas • Statutory loss after tax of $86.0 million after significant items of $79.4 million • Underlying loss after tax of $6.6 million • Cash generated by operating activities up 134% to $48.1 million Sales revenue $ million Statutory net profit after tax $ million Underlying net profit after tax $ million 78.1 75.5 67.5 39.1 27.4 27.0 -12.3 -12.1 -34.8 -86.0 13.3 9.8 -2.8 -8.7 -6.6 2016 2017 2018 2019 2020 2016 2017 2018 2019 2020 2016 2017 2018 2019 2020 Net cash from operating activities $ million Net cash/(debt) $ million Total equity $ million 48.1 147.4 111.0 49.8 443.9 433.7 351.1 285.0 91.6 -53.9 -97.8 22.2 20.5 7.9 4.1 2016 2017 2018 2019 2020 2016 2017 2018 2019 2020 2016 2017 2018 2019 2020 4 Operations and reserves • One lost time injury • Production up 19% to 1.56 MMboe • Sole offshore project completed, production commenced, firm supply delayed pending plant completion • Gas exploration successful with Annie and Dombey gas discoveries Safety Lost time injury frequency rate Production MMboe Proved and Probable reserves MMboe 3.53 1.49 1.56 1.31 52.4 52.7 49.9 0.96 0.46 0.0 0.0 0.0 11.7 3.0 2016 2017 2018 2019 2020 2016 2017 2018 2019 2020 2016 2017 2018 2019 2020 Equity Share price cents at 30 June 54.0 38.0 38.5 37.5 21.5 Basic earnings per share cents Market capitalisation $ million at 30 June 1.8 -0.7 -1.8 876 616 608 -5.3 433 2016 2017 2018 2019 2020 2016 2017 2018 2019 2020 2016 2017 2018 2019 2020 -10.1 94 5 Overview of operations Gas supply Sales rose because Sole started production. Outcomes below expectations due to late and incomplete Orbost Gas Processing Plant commissioning. Oil production Cash generating oil production. Gas sales PJ Gas revenue $ million Gas reserves Proved and Probable PJ 2020 2019 8.3 63.6 296 6.6 52.3 311 Crude oil & condensate production million bbl Crude oil revenue $ million Average oil price A$/bbl 2020 2019 0.20 14.5 0.24 23.2 83.75 102.52 Crude oil direct operating cost A$/bbl 35.17 36.45 Crude oil reserves Proved & Probable million barrels 1.6 1.8 • Gas sales revenue rose 22% • Completion of largest oil drilling campaign • New gas agreements negotiated for supply to Visy and Visy Glass International • Sole term supply contracts deferred to FY21 pending Orbost Gas Processing Plant commissioning involving 16 wells: 2 exploration wells, 13 appraisal wells and 1 development • 3 appraisal wells cased and suspended as future oil producers Gas contract book by term PJ Gas supply by source PJ 3 2.1 6.2 6.6 2019 2020 Otway Gippsland 115 150 28 Contracted 1 year or less Contracted >3 years Subject to extension options Uncontracted 6 Exploration and Development Sole offshore development completed within budget. Annie and Dombey gas discoveries. Health, Safety, Environment and Community Single Lost Time Injury. Bushfire recovery support and broader community engagement. Commitment to carbon neutrality for 2020 operations. Capital expenditure $ million Proved and Probable reserves MMboe Contingent Resources (2C) MMboe Wells drilled 2020 2019 76.7 49.9 34.9 18 200.0 Hours worked Recordable incidents Lost time injuries 52.7 26.9 0 2020 2019 283,672 505,300 1 1 0 0 • Sole offshore project completed for $335 million • Single lost time injury vs budget $355 million • Acquisition of Minerva Gas Plant, renamed Athena Gas Plant • Final Investment Decision on Athena Gas Plant Project in July 2020 • New gas field discoveries offshore and onshore Otway • Zero reportable environmental incidents • Participation and ongoing support for East Gippsland bushfire recovery • Commitment to carbon neutral operations for 2020 • Effective strategies implemented to prevent COVID transmission 2020 Capital expenditure by activity $ million 2020 Capital expenditure by region $ million 4 11 35 42 44 18 Exploration Development Otway Basin Gippsland Basin Cooper Basin Other 7 From the Chairman John Conde AO I am pleased to present Shareholders can take confidence in the competence Cooper Energy your company’s report has demonstrated in its core business of offshore gas development. to shareholders for the 2020 financial year. The success of the year’s drilling program yielded gas discoveries and increased the company’s Contingent Resources in the The period since 1 July offshore and onshore Otway Basin. The new discoveries, at Annie 2019 has been one of and Dombey, are being analysed for development or further enormous challenge for exploration. The securing of new acreage adjacent to these Australia and the world. discoveries, and in the Gippsland Basin, has consolidated the The Australian bushfires followed by company’s portfolio around proven gas provinces and established infrastructure located close to the key gas markets. the COVID-19 global Cooper Energy’s gas strategy has been well publicised and proven pandemic, considered to prescient. The generation of value from the strategy depends be without precedent, have had a huge impact on the markets on other factors including the quality of commercial analysis, and communities in which we operate. the capacity to establish and maintain win-win commercial On behalf of the board, I record our recognition and sympathy relationships and the aptitude for finding and securing value. for the personal, property or financial losses the recent local and Your company’s results in 2020 have once again highlighted Cooper global events have brought to people connected to our company. Energy’s commercial capabilities with outcomes expected to be of Care, collaboration, fairness and respect, and commitment are four of the seven core values that Cooper Energy seeks to embrace in all of its decisions. These values underpin our efforts to support our people and communities through their recovery. The fires, the pandemic and an unforeseen project delay have affected adversely the company’s results for 2020. However, although our results for the year were well below our expectations at the start of the year, we feel that we ended the financial year with a strong closing position. Our asset base and outlook will support growth in FY21 and the following years. long-term significance. These included securing new gas supply agreements and acquisition of the Minerva Gas Plant. The support and cooperation of valued counterparties facilitated management of our gas contract portfolio amidst the shifting start-up timelines brought by the delay of the Orbost Gas Processing Plant. Secondly, I highlight our health and safety performance. Results were inferior to the previous year, with one lost time injury compared with the injury-free performance in FY19. This was one injury too many and, for this reason, is an unsatisfactory result. However, there were positive elements that are noteworthy and provide relevant context: for all assets under our own control and The Managing Director’s Report and the Financial Report address management the company maintained safe operations, the lost these matters in detail. The 2020 Sustainability Report, which has been published alongside this report, documents the company’s performance, disclosures and objectives in respect of health and safety, environment, climate, community and its people. time injury having occurred on a contractor vessel on location, but not, at the time, under the direction of Cooper Energy. The company’s recordable incident frequency rate of 3.53 times per million hours worked compares favourably to the industry average 1 There are three features from these documents to which I draw of 5.27 times. particular attention. First, the company’s performance on the matters where it has direct responsibility. The offshore development, construction and commissioning of the Sole Gas Project was completed by Cooper Energy well within budget, on time and with zero lost time injuries or reportable environmental incidents. This is an exceptional performance. COVID-19 added a new dimension to the company’s safety management. As an energy supplier, Cooper Energy continued operations, with work arrangements at site, office and board levels all reconfigured to guard the health of employees and contractors and protect busines continuity. The board continued to meet and work effectively via video-conference facilities. The fluidity of social distance and health regulations required a proactive and adaptive response and your company is vigilant and maintaining readiness Unfortunately, our excellent offshore performance has been over- for further developments. shadowed by the delay to the completion onshore of the Orbost Gas Processing Plant which is owned and operated by APA Group. 1 National Offshore Petroleum Safety and Management Authority. 8 Thirdly, I highlight the company’s commitment to achieving carbon I record my thanks to all my board colleagues and to our Company neutrality. Cooper Energy has long maintained its commitment to operating with care for the environment as one of our core values. Engagement with our shareholders has confirmed their belief in the importance of south-east Australian gas for the region’s energy needs. It has also highlighted a deep and widely held conviction that companies should play their part in understanding, Secretary for their counsel and support in what has been a demanding year. In May, we welcomed Ms Vicky Binns and Mr Tim Bednall to the board, subject to confirmation by shareholders at this year’s annual general meeting. Each of these new directors brings valuable expertise to the board. We are fortunate to have their support and insights as we address the challenges to which I have referred earlier. and seeking to reduce, the impact of their activities on climate I acknowledge especially the contribution of my fellow non- and the environment. This year’s Sustainability Report outlines executive director Ms Alice Williams who is not seeking re-election your company’s progress. Most significant is our commitment to at the forthcoming AGM. Alice has been a valued member of the carbon neutrality for 2020 and to work to achieve this objective in board and has been part of the company’s significant growth, future years. Cooper Energy wants to play its part and is working contributing always to discussions. Alice has been Chairman of our to ensure ongoing improvement in the management of its Audit Committee for nearly seven years. She is a person of great integrity and loyalty, with an almost forensic ability to ensure that the financial affairs of the company were conducted always to the highest standard. On behalf of us all, thank you Alice. Finally, I record our appreciation to our Managing Director, David Maxwell, and all his team for their leadership during very challenging times and to the entire Cooper Energy team for their work and support. John Conde AO Chairman environmental impacts. Concluding comments and outlook This report has been finalised some six months after the first impacts of COVID-19 on all of us and on the Australian economy. As is evident in the company’s FY20 accounts, the energy sector has experienced contraction of demand and prices, but it is also poised for the eventual recovery in consumer confidence and economic activity. The timing and rate of this recovery is unknown, but Cooper Energy is well placed to navigate and grow during this uncertainty. The majority of the company’s gas reserves are subject to long term contracts, offering stable cash flows through take-or-pay terms and prices not linked to oil prices. Cooper Basin oil provides an additional source of cash flow from low cost production. The commencement of term gas supply from Sole, deferred in FY20, is expected to drive substantial growth in production, revenue and cash generation in FY21. Cash at 30 June was $131.6 million and capital expenditure plans are manageable as the company prepares for a resumption of offshore drilling on new gas projects in FY23. Underpinning these fundamentals are the company’s relationships, especially with its gas customers and financiers but also with the communities in which we operate and with relevant government regulators and other stakeholders. These relationships were fundamental to the Sole Gas Project proceeding. The board is cognisant and appreciative of the solidarity and commitment our customer and banking groups have shown us this year, supporting our strategy to bring new term gas supply to south-east Australia. 9 Managing Director’s Report David Maxwell Fellow shareholders, Whilst an injury-free performance is the only acceptable result, I do Your company’s results for the 2020 financial year were not what we expected at its outset. The promising start given by successful completion of the Sole offshore development, gas discoveries offshore and onshore and new gas contracts was ultimately overshadowed by non-completion of the Orbost Gas Processing Plant upgrade and the impact of low wish to acknowledge the efforts of our employees and contractors in restricting injuries to this single incident. A safe record is only achieved through the planning and vigilance of every employee, at every location, in every moment of the working year. On behalf of shareholders and the board of directors, I record our appreciation for their contribution to safe operations by Cooper Energy. The COVID-19 pandemic brought new dimensions to care for employee health and safety. Cooper Energy was an early responder in adopting working protocols and arrangements to protect its employees and maintain business continuity. The company’s efforts have been well supported by government agencies and the independent advisors we commissioned to guide our efforts. oil prices and of Coronavirus-19 (COVID-19) on energy markets. As an essential service, energy supply has not been directly These events resulted in the year’s production and cash flow affected by restrictions although, as I have noted in my opening outcomes being much lower than anticipated and contributed to and discuss later, there has been a significant financial impact the impairments which affected statutory profit. through flow-on impacts to energy markets and prices. The Discussion of these events and their significance is an important part of my report to you this year, together with our performance and plans in safety, environment, new projects and the status and outlook of our gas strategy. Notwithstanding that your company did not achieve the production and financial results targeted at the year’s outset, it has concluded 2020 with record production and revenue. The company has more growth assets in its portfolio, firm expectation of a step-change uplift in production and cash flow and a stronger position in the south-east Australian gas market. company’s unmanned subsea gas production is unaffected by restrictions, and office-based work continued through work-from- home and then revised socially distanced office configurations. Care and maintenance of the Athena Gas Plant has been ongoing using a skeleton crew and safe work practices. Participation in the regional communities where our operations are located is an integral element of our business model. One of these communities, East Gippsland, suffered great tragedy during the year from extensive bushfires. I record our sympathy for the loss experienced by the East Gippsland community, which included loss of human life, wildlife and farm stock as well as property and Health, safety, environment and community financial loss. Cooper Energy provided financial support and direct Operating with care is the first Cooper Energy value and the governing principle of our day-to-day activities and decision-making. help in organising logistics for supply of feed to farm animals immediately after the bushfires. The company has also committed to ongoing support for the communities in what will be a long- We have detailed our performance and impacts in the 2020 term recovery process. Sustainability Report, which has been released in parallel with this report and is available from the company’s website. There are three aspects I wish to highlight in this report: safety and health, community and climate. The measurement, disclosure and management of emissions has become a core concern for the community and investors. For Cooper Energy this requires us to understand and manage the delivery of energy required by the domestic, industrial, service and Our safety performance in 2020 fell just short of the injury-free commercial sectors whilst respecting the desire of our shareholders, standard we aspire to, and which was achieved in 2019. A lost employees and broader society for emissions reduction. time injury was recorded on the Ocean Monarch drilling rig whilst on location at VIC/P44 for the drilling of Annie-1. Thankfully the injured worker, who was employed by the drilling contractor, recovered and returned to work. The fact the injury was incurred whilst the rig was not under the supervision of Cooper Energy at the time reinforces the need for vigilance across the widest extent of our operations. 10 Gas has been identified by government and energy industry agencies as having a necessary role to play, as a lower carbon fuel, in the transition to a lower emissions world. In addition, Cooper Energy wants to play its part in emissions reduction directly. Accordingly we have, as detailed in the 2020 Sustainability Report, made the commitments for the achievement of carbon neutrality in respect of our 2020 operations and to work to achieve the same outcome in future years. Subsea 7 contractors inspecting flowline as it is spooled onto the construction vessel, Seven Eagle. I encourage shareholders to read the 2020 Sustainability Report construction and disruption brought by the East Gippsland to learn of the work the company is doing to promote safety, bushfires. Unexplained foaming has impaired the capacity of health and environment outcomes connected to its operations and the plant to produce at the level required for commissioning to advance diversity. The report can be read or downloaded from the be completed and for firm supply to commence. The impact company’s website www.cooperenergy.com.au. on Cooper Energy was that gas sales from Sole during the year Sole Gas Project were approximately 2 PJ at spot gas prices rather than the 12 PJ under term gas contracts anticipated at the beginning of the The completion of the offshore development of Sole in July was financial year. the culmination of more than 4 years of work by your company to analyse, acquire and then finance and develop the field. The offshore development was completed and commissioned injury- free, and well within budget. Final capital expenditure on the offshore project was $335 million compared with the budget of $355 million. Offshore production facilities and the reservoir have performed to expectations since production commenced. Unfortunately, delays with the onshore project managed by APA Group have necessitated deferral of the commencement of the long-term gas supply agreements, rescheduling of events within the company’s financing agreements and, ultimately, a Transition Agreement with APA to facilitate progress to the commencement of firm supply. Gas supply from the field commenced in March for plant commissioning purposes, a date significantly later than foreshadowed in the 2019 annual report due to delays in plant The Transition Agreement executed after year-end by Cooper Energy and APA unites both parties in identifying and overcoming the plant performance issues and generating revenue at the earliest juncture. The commercial framework of the agreement provides for the commencement of firm supply to Cooper Energy long-term customers in advance of plant practical completion at rates the plant is capable of supplying reliably. Cooper Energy and APA are working together to identify the root cause of the foaming and explore and implement technical solutions to lift performance to the required level. This includes Phase 2 plant works being planned for the December quarter 2020. The intended outcome is for Cooper Energy to be able to commence firm gas supply from Sole to customers within FY21 with the expectation achievement of higher processing rates will be targeted incrementally following the Phase 2 plant works. 11 Managing Director’s Report David Maxwell Financial results and position The company’s financial results, position and operating results are reported in detail in the Financial Report from page 35 of this report. The year’s statutory loss after tax of $86.0 million is principally attributable to significant items totalling $(79.4) million after tax, most of which arose from a review of asset carrying values and restoration provisions expensed at year-end. It is important to note these items have not arisen through trading and have not impacted the year’s cash flow. The charges have Exploration and development, projects for growth Since 2015 the company’s principal focus has been on the commercialisation and development of the Sole gas field. With the Sole offshore development complete, the focus shifted to the addition of new growth assets to the company’s gas portfolio. The $42 million commitment to exploration in FY20 was the largest yet by the company and resulted in the Annie gas discovery in the offshore Otway Basin and the Dombey gas discovery in the onshore Otway Basin. essentially been driven by two factors: revisions to uncontracted Annie is located near the Casino, Henry and Netherby gas fields gas price assumptions to recognise the lower energy prices and and associated infrastructure. The assessment of a Contingent lower energy demand brought by COVID-19; and revisions to Resource (2C) for the field was the principal factor in the 33% anticipated development and abandonment costs following the rise in the company’s 2C Contingent Resources of gas at 30 June FY20 drilling campaign, updated prices and regulatory expectations 2020. Commercialisation of the Annie gas field is being assessed and the recognition of foreign exchange and government bond as part of the Otway Phase 3 Development Project, which aims rate movements. The fall in gas prices during FY20 was substantial: as an indication, the average Victorian spot price for the month of June 2020 of to bring more than 100 PJ of gas (joint venture volume, Cooper Energy share is 50%) to market through development of Annie and undeveloped gas in the Henry gas field. $4.62/GJ was approximately half the average of $9.41/GJ for the Annie-1 was intended, as reported in last year’s annual report, previous corresponding period. The adoption of 2020 prices and to be the first of a 2-well program in the offshore Otway Basin. expectations to valuation of the company’s uncontracted gas and Unfortunately, the second well in the program, Elanora, could projects required impairment to the carrying value of some assets. not proceed due to unresolved issues with the drilling rig Notwithstanding the year’s lower prices, I note that developments mooring system. during the year (which I discuss later under the heading “Gas strategy update”) have affirmed the merit of the company’s gas strategy and the prospects for our uncontracted gas in the coming years. Energy market analysis conducted during the year has highlighted the market prospects of new gas supply to south-east Australia from 2023 onwards. This market opportunity, combined with the findings of subsurface and economic analysis of the prospects in The year’s underlying loss of $6.6 million for the year compares our offshore Otway permits presents a compelling case for further with an underlying profit of $13.3 million in the previous year. drilling. Testing of Elanora, together with several other offshore The movement is consistent with a year when an increase in costs Otway prospects, is being considered for an offshore campaign consistent with the development of the business’ asset base was being planned to commence in the first half of FY23, subject not matched by the anticipated growth in revenue due to the to rig availability. deferral of Sole term gas supply commencement. These additional costs included the commencement of expenses related to the Sole offshore development following its completion, such as amortisation and interest on the project finance facility, which had been previously capitalised. The company has concluded the year with net debt of $97.8 million, which comprises cash of $131.6 million and debt of $229.4 million. The debt is within the project finance facility established with The company’s portfolio of offshore Otway exploration opportunities was expanded with the acquisition of VIC/P76 during the year. VIC/P76 is well situated for Cooper Energy, with its eastern border adjoining VIC/L22, which contains the Minerva gas field, and its western border adjoining VIC/P44 where the Annie gas field was discovered. A small portion of the Annie gas field has been mapped to extend into VIC/P76, which also holds other gas prospects including Nestor, a low risk gas exploration opportunity senior banks to fund the company’s expenditure for the Sole Gas similar to Annie. Project. The delay to completion of the Orbost Gas Processing Plant has necessitated rescheduling of milestone dates for the facility. Cooper Energy has maintained dialogue with its financiers who have reiterated their support for the project. It is expected a schedule of revised milestone dates will be agreed with financiers during the first half of FY21 after the plans for the Phase 2 plant works are finalised. Dombey-1 made a gas discovery in the onshore Otway Basin. Although initial good flow rates on test were not sustained, the subsequent re-pressurisation of the reservoir gives encouragement for a larger gas accumulation than the test results initially indicated. The well also de-risked and highlighted potential in the broader Penola Trough region. We expect to conduct further exploration through acquisition of 3D seismic and follow-up drilling in this region in the coming years. The timelines involved are medium term; 12 Athena Gas Plant but consistent with our strategy, the fundamentals are right: the Our focus is on south-east Australia, where the supply onshore Otway Basin is a proven gas province, with existing gas opportunities we identified in 2012 led to the commercialisation of infrastructure, nearby markets and the development cost threshold the Sole gas field and where we see new opportunities emerging is very cost competitive. from 2023 onwards. The acquisition of the Minerva Gas Plant was the other significant The Sole project is illustrative of our approach: early identification growth initiative for the year. Upgrading and integration of the and analysis of a future supply opportunity, followed by the securing plant will be the company’s major development expenditure item and commercialisation of an undeveloped gas field identified as in FY21. Once connected, the Athena Gas Plant (as it has been a competitive source of new supply. The commercialisation of renamed) will be the hub for our offshore Otway operations. Sole was enabled by the support of gas customers, financiers and Connection of the plant to our gas operations is expected to be completed in the September quarter 2021, although this is subject to the threat of disruption to supply chain or restrictions arising investors, and APA Group and their collective willingness to join the company in making commitments necessary to bring a new source of gas supply to market. from COVID-19. Athena is expected to bring lower processing Market developments in 2020 adversely affected short term gas costs, higher productivity and, most importantly, a processing hub prices, signalled tightening gas supply from 2023 and reaffirmed with capacity for discoveries such as Annie. The plant’s location in the merit of the company’s gas strategy and the prospects for its western Victoria is also ideally suited for supply to South Australia undeveloped gas. and Victoria. Gas strategy and market update Cooper Energy aims to create value from gas through management of a portfolio of gas supply contracts and production sources to optimise returns to shareholders. The weakening of international energy demand and prices brought by the Coronavirus pandemic had flow-on effects to spot prices for domestic gas and will impact long-term supply. Low LNG spot prices saw an increase in gas flows from Queensland to south-east Australia, increasing domestic supply availability and reducing spot prices. Exploration and development spending was also curtailed. It is expected the soft spot prices will persist into FY21. 13 Managing Director’s Report David Maxwell However, government projections (Australian Energy Market This has been advanced during the year by the discovery of the Operator, “AEMO”) issued during the year have forecast an Annie gas field, securing of adjoining exploration acreage, the inversion of market dynamics for south-east Australia within two progression of development studies for Annie and undeveloped to three years as local production falls. AEMO’s forecast, and Henry gas, the planning of the Manta-3 appraisal and development the company’s own analysis, sees new gas supply opportunities well and analysis and the ranking of exploration prospects for a emerging from 2023 as production from currently producing fields drilling program anticipated in FY23. Our portfolio features declines. Moreover, these analyses, prepared earlier in the year, do a range of exploration, development and appraisal opportunities not incorporate the negative impact on supply to be expected from with maturation timelines that dovetail neatly with the market the subsequent reductions to capital expenditure in 2020 and 2021. opportunities foreseen in south-east Australia. The questions these developments present for Cooper Energy and FY21 outlook its gas strategy are: a) how is the company placed to manage exposure to the soft market conditions of FY20 and expected for FY21 ? ; and b) how is the company positioned to capitalise on the opportunities foreseen from FY23 onwards? In respect of the near term, the benefits of the company’s strategy of maintaining a ‘long’ contract book is evident. The company’s principal source of gas production, Sole, has almost fully contracted term contract capacity to 2025. The delays with the Orbost Gas Processing Plant completion mean the company has not yet commenced these term contracts and has been supplying available Sole production at current spot prices. The initiation of the term supply contracts is targeted for by around mid-FY21 after establishment of a firm supply capability at the Orbost Plant. From this point on, the large majority of sales are expected to be at the term gas contract prices previously negotiated. Most of the company’s uncontracted 2P gas reserves are located in the Otway Basin, where contracting terms have been affected by the company’s reliance on third party processing capability. This situation will change with the completion of the Athena Gas Plant Project, which will give the company access to firm supply capability for the remaining life of the producing fields. Approximately 1 PJ of the company’s Otway Basin production has been contracted for 2021. The company is currently considering its options for the contracting of its uncommitted gas prior to the anticipated commencement of supply from the Athena Gas Plant and in the years thereafter. Our portfolio-style management of gas contracts provides some optionality between Otway and Gippsland basin supply. Looking to the longer term, the opportunity to bring new south-east Australian gas supply to market from 2023 has been a key strand in the company’s gas strategy since 2018 when preparations began for the offshore Otway drilling program and the commitment made to acquire the Minerva Gas Plant. There are 2 principal points of focus in our new year outlook: • Sole in the Gippsland Basin from where we expect to realise uplift in production, revenue and cash flow in FY21. The quantum of production growth will be dependent on at least two milestones for the Orbost Gas Processing Plant: the commencement of firm supply and the consequent initiation of the term gas supply contracts; and • the offshore Otway Basin, where our work on the Athena Gas Plant Project and new development opportunities provides us with a dedicated processing facility and new gas projects for growth in future years. While the delays of the previous year have been frustrating, I can assure shareholders your company’s team is eager to deliver production, revenue and cash earnings gains in FY21 and to translate the opportunities within its portfolio into new sources of gas supply to south-east Australia and the next wave of growth for Cooper Energy. In closing, I would like to record my appreciation for the support of our shareholders, our financiers and our customers and the efforts and enterprise of our employees and contractors during the year. I also want to acknowledge the support and guidance provided by the board during a period of extraordinary and demanding events. FY20 has been marked by tragedy in the communities in which we work and live, a mixture of achievement and disappointment with our business expectations and the disruption, stress and harm brought by the pandemic. We are mindful of, and acknowledge, the impacts of these events during the year and ongoing. We reaffirm our commitment to the well-being and development of the communities in which we operate; to our people and their families; and to rewarding the trust and patience of our shareholders and financiers. David Maxwell Managing Director 14 Cooper Energy’s Legacy Foundation provided financial support to the Royal Flying Doctor Service to deliver critical health services following the Gippsland bushfires and in response to COVID. 15 Reserves and Resources Reserves Cooper Energy’s 2P Reserves at 30 June 2020 are assessed to be 49.9 million barrels of oil equivalent (MMboe) compared with the previous corresponding result of 52.7 MMboe. Key factors contributing to the movement in 2P Reserves were production of 1.6 MMboe in FY20, PEL 92 drilling results and future development programs, adjustments to gas plant fuel requirements and de-booking of remaining reserves following Minerva field shut-in in September 2019. Reserves at 30 June 2020 Category Unit 1P (Proved) 2P (Proved and Probable) 3P (Proved, Probable and Possible) Developed Undeveloped Total Developed Undeveloped Total Developed Undeveloped Total Sales Gas PJ Oil + Cond MMbbl Total 1 MMboe 184 0.7 30.7 29 0.1 4.8 213 0.8 35.5 255 1.3 42.9 41 6.6 6.9 296 6.9 49.9 344 1.9 58.0 49 0.4 8.5 393 2.3 66.6 1 Reserves exclude Cooper Energy’s share of future fuel usage. Totals may not reflect arithmetic addition due to rounding. The Reserves information displayed should be read in conjunction with the information in the Notes on calculation of Reserves and Contingent Resources provided in this document. Year-on-year movement in 2P Reserves (MMboe) Proved and Probable 2P Reserves (MMboe, net) Category Cooper Otway Gippsland Reserves at 30 June 20191 FY20 Production 2 Revisions/Aquisitions Reserves at 30 June 20203 1.8 (0.2) (0.0) 1.6 10.9 (1.0) (0.4) 9.5 40.0 (0.4) (0.8) 38.8 Total 52.7 (1.6) (1.2) 49.9 1 As announced to the ASX on 12 August 2019. 2 Otway and Cooper Basin production from 1 July 2019 to 30 June 2020 (inclusive). 3 Totals may not reflect arithmetic addition due to rounding. Reserves by basin and product at 30 June 2020 Category Unit 1P (Proved) 2P (Proved and Probable) 3P (Proved, Probable and Possible) Cooper Otway Gippsland Total 1 Cooper Otway Gippsland Total 1 Cooper Otway Gippsland Total 1 Reserves at 30 June 2020 Developed and Undeveloped (net to Cooper Energy) Developed Sales Gas PJ Oil + Cond MMbbl Developed total 1 MMboe Undeveloped Sales Gas PJ Oil + Cond MMbbl Undeveloped total 1 MMboe Total 1, 2 MMboe 0.0 0.7 0.7 0.0 0.1 0.1 0.8 9.1 0.0 1.5 28.8 0.0 4.7 6.2 174.4 183.5 0.0 0.7 28.5 30.7 0.0 0.0 0.0 28.8 0.1 4.8 28.5 35.5 0.0 1.3 1.3 0.0 0.3 0.3 1.6 17.2 237.5 254.7 0.0 2.8 40.6 0.0 6.6 9.5 0.0 1.3 38.8 42.9 0.0 0.0 0.0 40.6 0.3 6.9 38.8 49.9 0.0 1.9 1.9 0.0 0.4 0.4 2.3 23.7 319.8 343.5 0.0 3.9 49.5 0.0 8.1 0.0 1.9 52.3 58.0 0.0 0.0 0.0 49.5 0.4 8.5 12.0 52.3 66.6 1 The conversion factor 1 PJ = 0.163 MMboe has been used to convert from Sales Gas (PJ) to oil equivalent (MMboe) for the Otway and Gippsland basins. 2 The method of aggregation is by arithmetic sum by category. As a result, the 1P estimates may be conservative and the 3P estimates may be optimistic due to the effects of arithmetic summation. 16 Contingent Resources Cooper Energy’s 2C Contingent Resources at 30 June 2020 have increased since 30 June 2019 by 8.0 MMboe to 34.9 MMboe. The key factor contributing to the revision is the booking of Annie gas resource following exploration success at Annie-1 in September 2019. Contingent Resources at 30 June 2020 Category 1C 2C 3C Basin Gippsland Otway Cooper Total 1 Gas PJ Oil/Cond MMbbl Total MMboe 84 32 0.0 116 2.2 0.03 0.4 2.6 15.9 5.3 0.4 21.6 Gas PJ 135 52 0.0 187 Oil/Cond MMbbl Total MMboe 3.4 0.1 0.8 4.4 25.5 8.5 0.8 34.9 Gas PJ 212 64 0.0 276 Oil/Cond MMbbl Total MMboe 5.4 0.1 1.4 6.9 40.1 10.5 1.4 52.0 1 Totals may not reflect arithmetic addition due to rounding. The Contingent Resources information displayed should be read in conjunction with the information in the Notes on calculation of Reserves and Contingent Resources provided in this document. Year-on-year movement in Contingent Resources (MMboe) Category Contingent Resources at 30 June 2019 1, 2 Revisions Contingent Resources at 30 June 2020 1, 2 1 As announced to the ASX on 12 August 2019. 2 Totals may not reflect arithmetic addition due to rounding. 1C 18.0 3.7 21.6 2C 26.9 8.0 34.9 3C 41.5 10.5 52.0 Notes on calculation of reserves and resources Reference points for Cooper Energy’s petroleum Reserves and Cooper Energy prepares its petroleum Reserves and Contingent Resources in accordance with the definitions and guidelines in the Society of Petroleum Engineers (SPE) 2018 Petroleum Resources Management System (PRMS). The estimates of petroleum Reserves and Contingent Resources contained in this statement are as at 30 June 2020. All Reserves and Contingent Resources figures in this document are net to Cooper Energy unless otherwise stated. The Reserves exclude Cooper Energy’s share of future fuel usage. Cooper Energy has completed its own estimation of Reserves and Contingent Resources for its operated Otway and Gippsland Basin assets. Elsewhere Reserves and Contingent Resources estimation is based on assessment and independent views of information Contingent Resources and production are defined where normal operations cease, and petroleum products are measured under defined conditions prior to custody transfer. Fuel, flare and vent consumed prior to the reference point is excluded. Petroleum Reserves and Contingent Resources are prepared using deterministic and probabilistic methods. The Reserves and Contingent Resources estimate methodologies incorporate a range of uncertainty relating to each of the key reservoir input parameters to predict the likely range of outcomes. Project and field totals are aggregated by arithmetic summation by category. Aggregated 1P and 1C estimates may be conservative, and aggregated 3P and 3C estimates may be optimistic due to the effects of arithmetic summation. provided by the permit Operators (Beach Energy Ltd for PEL 92 and Totals may not exactly reflect arithmetic addition due to rounding. Senex Ltd for Worrior Field). The conversion factor of 1 PJ = 0.163 MMboe has been used to convert from Sales Gas (PJ) to Oil Equivalent (MMboe). 17 Reserves and Resources Reserves Under the SPE PRMS 2018, “Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions”. The Otway Basin totals comprise the arithmetically aggregated project fields (Casino-Henry-Netherby and Minerva). The Cooper Basin totals comprise the arithmetically aggregated PEL 92 project fields and the arithmetic summation of the Worrior project Reserves. The Gippsland Basin total comprises Reserves in Sole only. Contingent Resources Under the SPE PRMS 2018, “Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable owing to one or more contingencies”. The assessment used deterministic simulation modelling and probabilistic resource estimation for the Waarre C Formation in the Annie Field. This methodology incorporates a range of uncertainty relating to each of the key reservoir input parameters to predict the likely range of outcomes. This approach is consistent with the definitions and guidelines in the Society of Petroleum Engineers (SPE) 2007 Petroleum Resources Management System (PRMS). Qualified Petroleum Reserves and Resources Evaluator Statement The information contained in this report regarding the Cooper Energy Reserves and Contingent Resources is based on, and fairly represents, information and supporting documentation reviewed by Mr Andrew Thomas who is a full-time employee of Cooper Energy Limited holding the position of General Manager – Exploration & Subsurface, holds a Bachelor of Science (Hons), is a member of the American Association of Petroleum Geologists and the Society of Petroleum Engineers, is qualified in accordance with ASX listing rule The Contingent Resources assessment includes resources in the 5.41, and has consented to the inclusion of this information in the Gippsland, Otway and Cooper Basins. In the Otway Basin, the form and context in which it appears. Contingent Resources assessment at Annie gas field in VIC/P44 reported on 24 February 2020 has been upgraded at 30 June 2020. The change is a result of continued technical studies following the Annie-1 discovery announcement to the ASX on 6 September 2019. The update has resulted in an immaterial increase to Annie 2C gas Contingent Resources from 54.5 PJ to 57.4 PJ (100% gross working interest). Movement in Reserves 12 months to 30 June 2020 Reserves1 Production FY19 Revisions/Aquisitions Reserves 2, 3 FY20 1 As announced to the ASX on 12 August 2019. Proved (1P) MMboe 38.1 (1.6) (0.9) 35.5 Proved and Probable (2P) Proved, Probable and Possible (3P) MMboe MMboe 52.7 (1.6) (1.2) 49.9 73.3 (1.6) (5.1) 66.6 2 The conversion factor 1 PJ = 0.163 MMboe has been used to convert from Sales Gas (PJ) to oil equivalent (MMboe) for the Otway and Gippsland basins. 3 The method of aggregation is by arithmetic sum by category. As a result, the 1P estimates may be conservative and the 3P estimates may be optimistic due to the effects of arithmetic summation. 18 Far Saracen support vessell on location in Otway Basin. 19 Operations Production Cooper Energy’s oil and gas production for the year totaled 1.56 MMboe compared with 1.31 MMboe in the previous year. The increase is due to the commencement of gas production from the Sole gas field in the Gippsland Basin. Safety A detailed report, and discussion of the company’s safety management and performance is provided in the 2020 Sustainability Report. The report, which has been released contemporaneously with the annual report can be viewed and downloaded from the company’s website www.cooperenergy.com.au. 20 Production: 12 months to 30 June 1 2020 2019 Gas PJ Crude oil and condensate ‘000 bbl Total million boe Gas PJ Crude oil and condensate ‘000 bbl Total million boe Gippsland Basin Otway Basin Cooper Basin 2.1 6.2 - 3.5 193 0.34 1.02 0.19 - 6.6 - - 4.7 238 - 1.07 0.24 1 All numbers rounded. Accordingly addition of individual numbers displayed may differ insignificantly from the totals quoted. Production by region MMboe 1.22 1.07 0.34 1.02 0.27 0.24 0.19 0.68 0.25 0.25 2017 2018 2019 2020 0.32 0.44 2016 Otway Basin Gippsland Basin Cooper Basin South Sumatra, Indonesia Safety metrics year ended 30 June 2020 2019 Hours worked Recordable incidents Lost time injuries Lost time injury frequency rate Total recordable injury frequency rate (TRIFR)1 Industry TRIFR2 283,672 505,300 1 1 3.53 3.53 5.27 0 0 0.0 0.0 3.48 1 TRIFR – Total Recordable Injury Frequency Rate all recordable incident data (Medical Treatment Injuries + Restricted Work/Transfer Case + Lost Time Injuries + fatalities) multiplied by 1,000,000 then divided by total hours worked. 2 Industry TRIFR is NOPSEMA benchmark for offshore Australian operations. Cuttings sample from 2,018 metres deep on the Annie-1 well, drilled in Q3 2019. 21 Operations Offshore Otway Basin The company’s interests in the offshore Production Otway Basin include: Year ended 30 June 2020 2019 • a 50% interest in, and Operatorship of, the producing Casino Henry Netherby (“Casino Henry”) Joint Venture (VIC/L24 Casino Henry • Gas PJ 5.89 and VIC/L30). Mitsui E&P Australia and • Condensate kbbl 2.76 its associated entities (“Mitsui”) hold the remaining 50% interest; Minerva • Gas PJ • a 50% interest in, and Operatorship, of production licences VIC/L33 and VIC/L34 • Condensate kbbl which contain part of the Black Watch Total MMboe 0.32 0.76 1.02 5.52 1.7 1.0 3.0 1.07 gas field. Mitsui holds the remaining 50% interest; • a 50% interest in, and Operatorship of, the VIC/P44 exploration permit. Mitsui holds the remaining 50% interest; • a 100% interest in the exploration permit VIC/P76; As at 30 June Developed • Gas PJ Undeveloped • a 50% interest in, and Operatorship • Gas PJ of, the Athena Gas Plant (previously known as the Minerva Gas Plant) located Total Gas PJ 17 41 58 24 43 67 onshore Victoria. Mitsui holds the remaining 50% interest; and Contingent Resource (2C) • a 10% interest in the Minerva gas field As at 30 June 2020 2019 (VIC/L22) which ceased production • Gas PJ 52 18 on 3 September. BHP Petroleum is the Operator and holder of a 90% interest. Casino Henry The Casino Henry gas operations produce gas and condensate from the Casino field in VIC/L24, and the Henry and Netherby fields in VIC/L30. The fields are located 17 km to 25 km offshore Victoria in water depth ranging from 65 m to 71 m. Netherby-1), with production from a maximum of 3 wells at any one time. Gas produced from Casino Henry is transported by a 12-inch subsea pipeline to the processing facility at Iona owned by Lochard Energy. Casino was brought online in January 2006 and the Henry and Netherby fields in February 2010. Cooper Energy’s share of gas from Casino Henry is currently sold to AGL Energy under a 12-month contract to 31 December 2020. The company’s gas production for the subsequent calendar year is partly 2022 calendar years. Minerva The Minerva gas field is located in production licence VIC/L22 located 9 km offshore Victoria in a water depth of approximately 60 metres. The field reached end-of-life during the year and was shut-in in September 2019. The company’s share of production from Minerva for the year was 0.32 PJ and 0.76 kbbl barrels of condensate compared to the previous year’s contribution of 1 PJ of gas and 3.0 kbbl of condensate. Athena Gas Plant Project The Athena Gas Plant is located approximately 5 km north-west of Port Campbell and is connected directly to the SEAGas Port Campbell to Adelaide Pipeline and to the South West Pipeline, owned by APA Group. The plant was commissioned in Proved and Probable Reserves contracted. Cooper Energy have contracted 2020 2019 supply of 1 PJ from Casino Henry to Visy Glass International in both 2021 and The licences are covered entirely by January 2005 as the Minerva Gas Plant and high-quality 3D seismic surveys acquired entered care and maintenance following between 2001 and 2007. The hydrocarbon the cessation of production at Minerva. reservoirs discovered and produced to date are in the Cretaceous Waarre Formation. The depth of the top Waarre Formation at the discovered fields range between approximately 1,500 metres to 2,000 metres. As foreshadowed in the 2019 Annual Report, Cooper Energy and Mitsui acquired the plant in December 2019 for the purpose of processing gas from Casino Henry and gas discoveries made in the region. Casino Henry consists of a subsea The Athena Gas Plant has gas processing development comprising four producing capacity of approximately 150 TJ/day and wells (Casino-4, Casino-5, Henry-2 and hydrocarbon liquids processing facilities. 22 Adelaide Warrnambool PEP 168 (50%) Cooper Energy tenement Gas field Gas pipeline VICTORIA Melbourne Processing Casino Henry gas through Minerva is expected to deliver processing cost and productivity benefits. Final Investment Decision on the project to connect the plant was taken after year- end. The plant is expected to be ready to receive first gas from Casino Henry in the September quarter 2021, although the potential for delays arising from COVID-19 is noted. Otway Phase 3 Development Project The Otway Phase 3 Development Project VIC/L34 (50%) VIC/L33 (50%) Speculant Halladale Black Watch VIC/P44 (50%) Martha Iona Gas Plant Athena Gas Plant (50%) VIC/P44 (50%) Annie VIC/L30 (50%) Henry Netherby Minerva VIC/L22 (10%) Casino 0 10 kilometres VIC/P44 (50%) VIC/P76 (100%) VIC/L24 (50%) (OP3D) involves development of the Annie Otway 160AR gas field and infill drilling of the Henry gas field to enable production of more than 100 PJ of gas (gross joint venture volume, Cooper Energy share 50%) via the Athena Gas Plant. OP3D is currently in the Concept Select phase. The project is scheduled to complete this phase in the first half of FY21. Development drilling required for OP3D could be incorporated into the broader drilling rig program planned to commence in the second half of calendar 2022, enabling first gas from late in FY23. Black Watch (VIC/L33 and VIC/L34) an extended reach onshore well. Cooper at Annie-1. Drilling of Elanora-1 will be Energy is pursuing commercial agreement considered for a drilling campaign being which recognises its equity share of Black planned to commence in FY23, subject to Watch gas reserves. Exploration Annie gas discovery A two-well gas exploration program in the offshore Otway Basin was launched in August 2019. rig availability. VIC/P76 VIC/P76 was awarded to Cooper Energy 100% in September 2019. The granting of VIC/P76 consolidated Cooper Energy’s offshore Otway acreage position around existing infrastructure and added to the The first well, Annie-1 in VIC/P44, made exploration prospect inventory. The permit a new gas field discovery, identifying a adjoins the Annie gas discovery and gross 70 metre gas column in the primary Casino production licence and is traversed target Waarre C formation with net gas by the Casino gas pipeline, which is to be pay thickness of 62 metres. A Contingent connected to the Athena Gas Plant. Cooper Energy has a 50% interest in Resource assessment was issued on 24 production licences VIC/L33 and VIC/L34 February. Annie is assessed to hold gross which were granted during the year to 2C Contingent Resources of 57 PJ1, with the company and its joint venture partner Cooper Energy’s equity share being 50%. Mitsui. The licences comprise the same Development of the field is being assessed area as the Retention Leases VIC/RL11 under the Otway Phase 3 Development and VIC/RL12 previously held by Cooper Project discussed under Offshore Otway Energy and Mitsui and contain part of the development, following. There are no previous wells drilled within the permit area. Good quality 3D seismic data covers most of the permit, from which Cooper Energy has identified several amplitude-supported prospects. The most significant, Nestor, has many similarities to the Annie gas discovery including the Waarre C reservoir, trap configuration Black Watch gas field which extends into adjoining production licences held by Beach Energy Limited (“Beach”). Drilling of the second well in the program, and potential resource size. Subsurface Elanora-1 in VIC/L24, was deferred analysis of this prospect, and others, has following repeated loss of tension on commenced with a view to identifying Beach commenced production from its the mooring lines attached to the Ocean the preferred candidate for drilling in the portion of the field during the year from Monarch drilling rig whilst on location campaign being planned for FY23. 1 Contingent Resource for the Annie gas resource was announced to ASX on 24 February and updated on 31 August 2020. Cooper Energy confirms that it is not aware of any new information or data that materially affects the information included in these announcements and that all the material assumptions and technical parameters underpinning the estimates in the announcements continue to apply and have not materially changed. 23 Operations Gippsland Basin Production Year ended 30 June • Gas PJ Sole 2020 2.10 2019 - The Sole gas field is located 36 km offshore Victoria in water depths of approximately Proved and Probable Reserves At 30 June • Gas PJ 2020 238 2019 245 Contingent Resources 125 m. The field is connected to APA Group’s (“APA”) Orbost Gas Processing Plant by a 65 km pipeline and umbilical control system. The plant, formerly known as the Patricia Baleen Gas Plant, is connected to the Eastern Gas Pipeline. Sole is an entirely subsea production system comprising wells, Sole-3 and Sole-4, with subsea wellheads, manifold 2020 2019 and tieback and control via the Orbost At 30 June • Gas PJ • Oil/Condensate MMbbl 135 3.4 121 3.4 Cooper Energy’s interests in the Gippsland Basin comprise: • a 100% interest, and Operatorship of, VIC/L32 which contains the Sole gas field; • a 100% interest and Operatorship of VIC/RL13, VIC/RL14 and VIC/RL15, which contains the Manta gas and liquids resource; • a 100% interest, and Operatorship of, VIC/RL16, which contains the shut-in and largely depleted Patricia-Baleen gas field; • a 100% interest in the Patricia Baleen to Orbost gas pipeline; and • a 100% interest in, and Operatorship, of the exploration permits VIC/P72 and VIC/ P75 located in the Gippsland Basin. plant. Development of the field was completed in July 2019. Gas production from Sole commenced later, and was lower, than anticipated due to delays in construction and commissioning of the Orbost Gas Processing Plant. Construction work to upgrade the plant to process gas from Sole was completed in January 2020. Commissioning of the plant is yet to be completed. Sole supplied 2.1 PJ of gas for commissioning purposes to 30 June, all of which was sold to gas customers on a spot basis. under a Transition Agreement signed after year end to establish a firm supply capability at the Orbost Gas Processing Plant and to progress initiatives to improve plant performance to the levels required for practical completion of the plant. Sole’s gas reserves are largely committed under long term take-or-pay contracts Resources 1 of 121 PJ of gas and 3.4 MMboe of condensate. There is prospective resource potential below the Manta gas field in the Manta Deep prospect. Manta is being considered as a follow-on development to Sole, its proximity to which enhances prospects for development. Analysis has identified significant synergies and cost savings if Manta is developed and operated in coordination with Sole in areas including control umbilicals, plant, redundancies and maintenance. Provision for Manta gas to access the Orbost plant for processing has been incorporated in the agreements executed by APA and Cooper Energy. An appraisal well is required prior to a development decision on the field’s Contingent Resources, which would also present the opportunity to test the Prospective Resource assessed in deeper reservoirs. Planning for this well, Manta-3, has progressed and the well may be drilled as part of the campaign targeted to commence in the first half of FY23 subject to rig availability. Patricia Baleen is a largely-produced offshore gas field located in production licence VIC/RL16 which is under care and maintenance after being shut-in in 2008. The field is connected to the Orbost Gas Processing Plant by a 24 km pipeline, also owned by Cooper Energy. Contingent Resources (2C) of approximately 14 PJ are assessed for the Patricia Baleen field at Proved and Probable Reserves of with industrial and utlility customers 238 PJ at 30 June compare to 245 PJ at in Australia. Commencement of these the beginning of the year. Factors in contracts has been deferred pending 30 June 2020. the movement of Proved and Probable establishment of a firm supply capability Reserves for the period were production from the plant. and a revision arising from the application of measured plant fuel usage by the Manta Orbost Gas Processing Plant and Sole gas The Manta gas field is located in retention heating value under production conditions. licences VIC/RL13, VIC/RL14 and VIC/RL15, 35 km from Sole and 58 km from the Orbost Gas Processing Plant. The field is assessed to contain 2C Contingent 1 Contingent Resource for the Manta gas and liquids resource was announced to ASX on 12 August 2019. Prospective Resource for the field was announced to the ASX on 4 May 2016. Cooper Energy confirms that it is not aware of any new information or data that materially affects the information included in the announcements of 12 August 2019 or 4 May 2016 and that all the material assumptions and technical parameters underpinning the estimates in the announcements continue to apply and have not materially changed. 24 APA and Cooper Energy are cooperating Patricia Baleen VICTORIA Orbost Sydney LIN E E E A S T E RN GAS P IP Orbost Gas Processing Plant (APA) Melbourne Lakes Entrance VIC/RL16 (100%) VIC/P72 (100%) VIC/L32 (100%) Patricia-Baleen Longtom Tuna Snapper Kipper Barracouta Marlin VIC/P75 (100%) Flounder Fortescue Sole Sole Manta Chimaera Chimaera Manta Basker Gummy VIC/RL15 (100%) VIC/RL14 (100%) Mackerel VIC/RL13 (100%) Blackback Bream Kingfish Cooper Energy tenement Gas field Oil field Gas pipeline Oil pipeline ppsland 122AR Gippsland_122AR 0 20 kilometres Plan area TA VIC/P72 It is anticipated an exploration well could Previous exploration within the area be drilled as part of the campaign being has been impacted by significant depth planned for FY23, subject to rig availability. conversion issues related to velocity VIC/P75 complexities above reservoir targets. However, recent advances in 3D seismic VIC/P75 was awarded to Cooper Energy reprocessing have provided greater clarity on a 100% equity basis in September for the mapping of subsurface structures. 2019. This exploration permit is located Interpretation has begun of licensed in the central area of the Gippsland 3D seismic data covering the permit that Basin surrounded by major oil and gas was reprocessed in 2018. VIC/P72 lies in proximity to several Esso-operated gas and oil fields including Snapper, Marlin, Sunfish and Sweetlips and the Longtom gas field operated by SGH Energy. Prospect analogues to the offset fields are identified in VIC/P72. The first three years’ guaranteed work program consists of 260 km2 of 3D seismic reprocessing and studies and the drilling of one exploration well. Interpretation of reprocessed 3D seismic and quantitative interpretation volumes fields including the Marlin, Snapper and Barracouta gas fields to the north and the Kingfish and Fortescue oil fields in the south and east respectively. Three- has been completed. Geological analysis dimensional seismic data is available to identify and rank select preferred candidates for drilling was conducted. covering most of the permit area. VIC/P75 was granted to Cooper Energy for a six-year term, the first three years of which entails a guaranteed work program consisting of seismic reprocessing and geological/geophysical studies. 25 Review of Operations Onshore Cooper Basin Cooper Energy holds interests in 35 • a 30% interest in PPL 207 which holds Proved and Probable Reserves petroleum retention licences and eleven the producing Worrior oil field; production licences in the South Australian Cooper Basin. The company’s activities are primarily focused on tenements held by the PEL 92 Joint Venture (‘PEL 92‘) on the • a 30% interest in PRL’s 231-233 and 237 • a 19.17% interest in the PRL’s 207-209, and western flank of the basin, which provided • a 20% interest in the PRL’s 183-190 approximately 12% of Cooper Energy’s (ex PEL-110). million barrels as at 30 June Developed • Crude oil Undeveloped • Crude oil total production and 94% of its liquids production for 2020. During the year the company participated Total in a total of 16 wells drilled by the PEL 92 • Crude oil Joint venture and tenement interests Joint Venture. The program included comprise: • a 25% interest in the PEL 92 Joint Venture which holds PRL’s 85 to 104, including the producing Butlers, Callawonga, Christies, Elliston, Germain, Parsons, Perlubie, Rincon, Rincon North, Sellicks, Silver Sands and Windmill oil fields; 13 appraisal wells, 1 development well and 2 exploration wells. Three appraisal wells were cased and suspended as future oil producers with all other wells being plugged and abandoned. Production million barrels as at 30 June 2020 2019 1.3 0.3 1.6 1.5 0.3 1.8 2020 2019 • Crude oil 0.19 0.24 Onshore Otway Basin Cooper Energy holds interests in five gas exploration after that date. All onshore production test yielded variable results, exploration licences and one retention Victorian permits remain in suspension recording measured gas flow exceeding licence in the onshore Otway Basin: until that time. Exploration • 30% interests in PEL 494, PRL 32, and PELA 680, South Australia. Beach Energy is the Operator and holds the remaining interest in these licences; • 50% interests in Bridgeport Energy- operated PEP 150 and Beach Energy- operated PEP 168 in Victoria; and The company’s primary focus in the suggests potential for a larger gas pool onshore Otway Basin is exploration of gas than interpreted via pressures. It is plays associated with the Sawpit and Pretty considered possible Dombey-1 drilled a Hill formations, primarily within the Penola smaller compartment connected to a Trough. The potential of this play was broader accumulation. proven by the gas field discovery made by 18 MM scfg/day before a subsequent decline in flow test pressure. Re-pressurisation of the reservoir after an extended shut-in • a 75% interest in PEP 171 in Victoria the Haselgrove-3 sidetrack well drilled by which may reduce by up to a further 25% Beach Energy in PPL 62 in 2017, a licence on fulfilment of farm-in arrangements surrounded by PEL 494. This region is executed with Vintage Energy. considered favourable for gas exploration Activity in the Victorian permits was suspended pursuant to the moratorium imposed by the state government on and development due to its prospectivity, existing infrastructure and local industrial and residential gas demand. Dombey-1 has derisked several other prospects within PEL 494 and upgraded the prospectivity of the north-western flank of the Penola Trough. The well also highlighted the need for better quality subsurface definition than afforded by the 2D seismic dataset currently available. Planning is underway for a 3D seismic acquisition onshore petroleum exploration and The PEL 494 joint venture drilled one well program at Dombey, which is most likely to production until 30 June 2020. The passage during the period, Dombey-1, which be conducted later in 2021. of the Petroleum Legislation Amendment resulted in a new gas discovery. The well Act 2020 during the year extended the encountered a gross gas column of 44.5 m, moratorium until 30 June 2021 and with net pay thickness of 25 m in the provided for resumption of conventional Pretty Hill Formation. A subsequent Dombey-1 was part funded by a $6.89 million PACE Gas Round 2 grant by the South Australian Government. 26 Cooper Basin Kingston SE SOUTH AUSTRALIA Naracoorte PEL 494 (30%) PRL 32 (30%) e Robe Beachport Dombey Penola Katnook Nangwarry PELA 680 (30%) Millicent Cooper Energy tenement Gas field Gas pipeline VICVICTORTORIAIA VICTORIA PEP 171 (75%) Hamilton Mount Gambier PEP 150 (50%) Portland Plan area 0 20 40 TAS kilometres Otway 161AR Otway 161AR Onshore Otway Basin 27 Portfolio Cooper Energy Exploration and Production Tenements Region: Australia Cooper Basin State Tenement Interest Location Area (km2) Operator Activities South Australia PPL 204 (Sellicks) 25% Onshore 2.0 Beach Energy Production PPL 205 (Christies/Silver Sands) PPL 207 (Worrior) PPL 220 (Callawonga) PPL 224 (Parsons) PPL 245 (Butlers) PPL 246 (Germein) PPL 247 (Perlubie/Perlubie South) PPL 248 (Rincon/Rincon North) PPL 249 (Elliston) PPL 250 (Windmill) PRLs 85-104 PRLs 231-233 PRL 237 PRLs 207-209 PRLs 183-190 Onshore Onshore Onshore Onshore Onshore Onshore Onshore Onshore Onshore Onshore 4.3 6.4 5.5 1.8 2.1 0.1 1.5 2.0 0.8 0.6 Beach Energy Production Senex Energy Production Beach Energy Production Beach Energy Production Beach Energy Production Beach Energy Production Beach Energy Production Beach Energy Production Beach Energy Production Beach Energy Production Onshore 1889.3 Beach Energy Exploration Onshore Onshore Onshore 277.2 Senex Energy Exploration 17.7 Senex Energy Exploration 296.5 727.5 Senex Energy Exploration Senex Energy Exploration 20% Onshore Otway Basin State Tenement Interest Location Area (km2) Operator Activities South Australia PEL 494 Victoria PELA 680 PRL 32 VIC/L22 VIC/L24 VIC/L30 VIC/L33 VIC/L34 VIC/P44 VIC/P76 PEP 150 PEP 168 PEP 171 Athena Gas Plant Onshore Beach Energy Exploration Onshore 1923.0 Beach Energy Exploration Onshore Offshore Offshore Offshore Offshore Offshore Offshore 36.9 58.0 199.0 200.0 127.0 Beach Energy Exploration BHP Production ceased Cooper Energy Production Cooper Energy Production Cooper Energy Development 6.0 Cooper Energy Development 599.0 161.0 Cooper Energy Exploration Cooper Energy Exploration 100% Offshore 50% 50% 75% 1 50% Onshore 3,212.0 Bridgeport Exploration Onshore 795.0 Beach Energy Exploration Onshore 1,974.0 Vintage Energy Exploration Onshore n/a Cooper Energy Gas Processing 1 Subject to farm-in agreement which will reduce Cooper Energy’s interest by up to a further 25%. 28 25% 30% 25% 25% 25% 25% 25% 25% 25% 25% 25% 30% 24% 19.17% 30% 30% 30% 10% 50% 50% 50% 50% 50% Zacc Paparella, Geologist and Phil Clegg, Technical Assistant on board Ocean Monarch at Annie-1. Gippsland Basin State Victoria Tenement VIC/RL16 VIC/RL13 VIC/RL14 VIC/RL15 VIC/L32 VIC/P72 VIC/P75 Interest Location Area (km2) Operator Activities 100% 100% 100% 100% 100% 100% 100% Offshore 134.0 Cooper Energy Retention Offshore Offshore Offshore Offshore Offshore Offshore 67.0 67.0 67.0 201.0 269.0 802.0 Cooper Energy Retention Cooper Energy Retention Cooper Energy Retention Cooper Energy Production Cooper Energy Exploration Cooper Energy Exploration 29 Board of Directors Board members have been photographed remotely, consistent with virtual board meetings having been held from late February 2020 due to Coronavirus restrictions. Chairman Mr John C. Conde AO B.Sc. B.E(Hons), MBA Independent Non-Executive Director Appointed 25 February 2013 Managing Director Mr David P. Maxwell M.Tech, FAICD Appointed 12 October 2011 Independent Non-Executive Director Timothy Bednall LLB (Hons) Appointed 31 March 2020 subject to confirmation by shareholders at the Company’s 2020 AGM Independent Non-Executive Director Victoria (Vicky) Binns B. Eng (Mining – Hons 1), Grad Dip SIA, FAusIMM, GAICD Appointed 2 March 2020 subject to confirmation by shareholders at the Company’s 2020 AGM Experience and expertise Mr Conde has extensive experience in business and commerce and in chairing high profile business, arts and sporting organisations. Previous positions include Non-Executive Director of BHP Billiton, Chairman of Pacific Power (the Electricity Commission of NSW), Chairman of the Sydney Symphony Orchestra, Director of AFC Asian Cup, Chairman of Events NSW, President of the National Heart Foundation and Chairman of the Pymble Ladies’ College Council. Current and other directorships in the last 3 years Mr Conde is Chairman of The McGrath Foundation (since 2013 and Director since 2012). He is President of the Commonwealth Remuneration Tribunal (since 2003) and Chairman of Dexus Wholesale Property Limited (since September 2020). He is Deputy Chairman of Whitehaven Coal Limited ASX: WHC (since 2007). Mr Conde is a former Chairman of Bupa Australia (2008-2018). Special responsibilities Mr Conde is Chairman of the Board of Directors. He is also a member of the People and Remuneration Committee and is the Chairman of the Nomination Committee. Experience and expertise Mr Maxwell is a leading oil and gas industry executive with more than 25 years in senior executive roles with companies such as BG Group, Woodside Petroleum Limited and Santos Limited. Mr. Maxwell has very successfully led many large commercial, marketing and business development projects. Prior to joining Cooper Energy Mr Maxwell worked with the BG Group, where he led its entry into Australia and Asia including a number of material acquisitions. Mr Maxwell has served on a number of industry association boards, government advisory groups and public company boards. Current and other directorships in the last 3 years Mr Maxwell is a Director of wholly owned subsidiaries of Cooper Energy Limited. He is also on the Board of the Australian Petroleum Production & Exploration Association (since 2018) and the Minerals and Energy Advisory Council (since 2019). Special responsibilities Mr Maxwell is Managing Director. He is responsible for the day to day leadership of Cooper Energy, and is the leader of the Executive Leadership Team. Mr Maxwell is also chairman of the HSEC Committee (being a management committee, not a Board committee). Experience and expertise Mr Bednall is a highly experienced and respected corporate lawyer and law firm manager. He is a partner of King & Wood Mallesons (KWM), where he specialises in mergers and acquisitions, capital markets and corporate governance, representing public company and government clients. Mr Bednall has advised clients in the oil and gas and energy sectors throughout his career. Mr Bednall was the Chairman of the Australian partnership of KWM from January 2010 to December 2012, during which time the merger of King & Wood and Mallesons Stephen Jaques was negotiated and implemented. He was also Managing Partner of M&A and Tax for KWM Australia from 2013 to 2014, and Managing Partner of KWM Europe and Middle East from 2016 to 2017. He was General Counsel of Southcorp Limited (which became the core of Treasury Wine Estates Limited) from 2000 to 2001. Current and other directorships in the last 3 years Mr Bednall is a board member of the National Portrait Gallery Foundation (since 2018). Special responsibilities Mr Bednall is a member of the People & Remuneration Committee, the Nomination Committee and the Risk & Sustainability Committee. Experience and expertise Ms Binns has over 35 years’ experience in the global resources and financial services sectors including more than 10 years in executive leadership roles at BHP and 15 years in financial services with Merrill Lynch Australia and Macquarie Equities. During her career at BHP, Ms Binns’ roles included Vice President Minerals Marketing, leadership positions in the metals and coal marketing business, Vice President of Market Analysis and Economics and was a member of the first BHP Global Inclusion and Diversity Council. Prior to joining BHP, Ms Binns held a number of board and senior management roles at Merrill Lynch Australia including Managing Director and Head of Australian Research, Head of Global Mining, Metals and Steel, and Head of Australian Mining Research. She was also co-founder and Chair of Women in Mining and Resources Singapore. Current and other directorships in the last 3 years Ms Binns is currently a Non- Executive Director of ASX-listed company Evolution Mining (since 2020). Special responsibilities Ms Binns is a member of the Audit Committee, the People & Remuneration Committee and the Risk and Sustainability Committee. 30 Independent Non-Executive Director Ms Elizabeth A. Donaghey B.Sc., M.Sc. Appointed 25 June 2018 Non-Executive Director Mr Hector M. Gordon B.Sc. (Hons) Appointed 24 June 2017 Executive Director 26 June 2012 – 23 June 2017 Independent Non-Executive Director Mr Jeffrey W. Schneider B.Com Independent Non-Executive Director Ms Alice J. M. Williams B.Com FAICD, FCPA, CFA Appointed 12 October 2011 Appointed 28 August 2013 Experience and expertise Mr Schneider has over 30 years of experience in senior management roles in the oil and gas industry, including 24 years with Woodside Petroleum Limited. He has extensive corporate governance and board experience as both a Non-Executive Director and chairman in resources companies. Current and other directorships in the last 3 years Mr Schneider does not currently hold any other directorships. Special responsibilities Mr Schneider is Chairman of the People and Remuneration Committee, and a member of the Nomination Committee and the Audit Committee. Experience and expertise Ms Donaghey brings over 30 years’ experience in the energy sector including technical, commercial and executive roles in EnergyAustralia, Woodside Energy and BHP Petroleum. Ms Donaghey’s experience includes Non-Executive Director roles at Imdex Ltd (an ASX-listed provider of drilling fluids and downhole instrumentation), St Barbara Ltd (a gold explorer and producer), and the Australian Renewable Energy Agency. She has performed extensive committee roles in these appointments, serving on audit and compliance, risk and audit, technical and regulatory, remuneration and health and safety committees. Current and other directorships in the last 3 years Ms Donaghey is a Non-Executive Director of the Australian Energy Market Operator (AEMO) (since 2017). Special responsibilities Ms Donaghey is a member of the Risk and Sustainability Committee, the People and Remuneration Committee and the Nomination Committee. Experience and expertise Mr Gordon is a geologist with over 40 years’ experience in the upstream petroleum industry, primarily in Australia and southeast Asia. He joined Cooper Energy in 2012, initially as an Executive Director – Exploration & Production and subsequently moved to his position as Non-Executive Director in 2017. Mr Gordon was previously Managing Director of Somerton Energy until it was acquired by Cooper Energy in 2012. Previously he was an Executive Director with Beach Energy Limited where he was employed for more than 16 years. In this time Beach Energy experienced significant growth and Mr Gordon held a number of roles including Exploration Manager, Chief Operating Officer and, ultimately, Chief Executive Officer. Current and other directorships in the last 3 years Mr Gordon is a Director of Bass Oil Limited ASX: BAS (since 2014). Special responsibilities Mr Gordon is the Chairman of the Risk and Sustainability Committee and a member of the Audit Committee. Experience and expertise Ms Williams has over 30 years of senior management and Board level experience in corporate, investment banking and Government sectors. Ms Williams has been a consultant to major Australian and international corporations as a corporate advisor on strategic and financial assignments. Ms Williams has also been engaged by Federal and State based Government organisations to undertake reviews of competition policy and regulation. Prior appointments include Director of Airservices Australia, Guild Group, Port of Melbourne Corporation, Telstra Sale Company, V/Line Passenger Corporation, State Trustees, Western Health and the Australian Accounting Standards Board. Ms Williams is also a former council member of the Cancer Council of Victoria. Current and other directorships in the last 3 years Ms Williams is a Non-Executive Director of Equity Trustees Ltd ASX: EQT (since 2007), Djerriwarrh Investments Ltd, Defence Health (since 2010) and not for profit Tobacco Free Portfolios (since 2018). Ms Williams has recently stepped down as a Member of the Foreign Investment Review Board. Ms Williams was a Non-Executive Director of the Victorian Funds Management Corporation for the period 2008 to 2018. Special responsibilities Ms Williams is the Chairman of the Audit Committee and a member of the Risk and Sustainability Committee. 31 Executive Leadership Team Executive Leadership Team members have been photographed remotely consistent with revised work arrangements whilst Coronavirus restrictions were in place. General Manager, Commercial and Business Development Eddy Glavas B.Acc CPA, MBA Mr Glavas joined Cooper Energy in August 2014 and has more than 20 years’ experience in business development, finance, commercial, portfolio management and strategy, including 18 years in the oil and gas sector. Prior to joining Cooper Energy, he was employed by Santos as Manager Corporate Development with responsibility for managing multi-disciplinary teams tasked with mergers, acquisitions, partnerships and divestitures. Prior roles within Santos included: Finance Manager WA and NT, where Mr Glavas was a member of the leadership team that managed a large asset portfolio; corporate roles in strategy and planning; and operational, commercial and finance roles for Santos’ Cooper Basin assets. General Manager, Projects and Operations Michael Jacobsen B. Eng (Hons) Company Secretary and General Counsel Amelia Jalleh BA, LLB (Hons), LLM Mr Jacobsen has 28 years experience in upstream and midstream oil and gas development projects. He has held various positions at Santos, Woodside and BHPB Petroleum. Mr Jacobsen’s experience includes managing major capital works projects with multi-discipline teams in the North Sea, Asia, and Australia. He has overseen the management of subsea and FPSO developments, fixed platforms and LNG plants. Prior to joining Cooper Energy Mr Jacobsen worked for Santos as part of the leadership team of the WA/NT business unit. Mr Jacobsen has extensive experience with oil field services company Halliburton managing subsea construction projects throughout Asia and Australia. Ms Jalleh joined Cooper Energy in August 2019 with more than 18 years’ experience in the international oil and gas industry, including senior corporate, commercial and legal roles in Australia, the Middle East, North America and South-East Asia for Talisman Energy, King & Spalding LLP and Santos. Prior to joining Cooper Energy, Ms Jalleh was Director, Business Development Asia-Pacific for Repsol, based in Singapore. Ms Jalleh holds a Masters of Laws (University of Melbourne) a Bachelor of Laws and Legal Practice (Hons) (Flinders University of South Australia) and a Bachelor of Arts (Flinders University of South Australia). Managing Director David Maxwell M. Tech FAICD Mr Maxwell is a leading oil and gas industry executive with more than 25 years in senior executive roles with companies such as BG Group, Woodside Petroleum Limited and Santos Limited. Mr. Maxwell has very successfully led many large commercial, marketing and business development projects. Prior to joining Cooper Energy Mr Maxwell worked with the BG Group, where he led its entry into Australia and Asia including a number of material acquisitions. Mr Maxwell has served on a number of industry association boards, government advisory groups and public company boards, including the Australian Petroleum Production and Exploration Association – Mr Maxwell is a recipient of the Australian Gas Association Silver Flame Award for his contribution to the gas industry. In September 2019, he was named the recipient of the 2019 John Doran Lifetime Achievement Award for out- standing long term achievement in the Australian oil and gas industry. 32 General Manager, HSEC and Technical Services Iain MacDougall BSc (Hons) Chief Financial Officer Virginia Suttell B.Com ACA GAICD, FGIA, FCIS Ms Suttell joined Cooper Energy in January 2017, bringing more than 25 years’ experience, including 20 years in publicly listed entities, principally in group finance and secretarial roles in the resources and media sectors. This included Chief Financial Officer and Company Secretary for Monax Mining Limited and Marmota Energy Limited from 2007 to 2016, and 2007 to 2015 respectively. Other previous appointments include 9 years at Austereo Group Limited, including Group Financial Controller from 2003 to 2006. A chartered accountant, Ms Suttell’s other previous employers include KPMG and Price Waterhouse. Mr MacDougall’s career in the upstream petroleum exploration and production business spans more than 30 years, prior to which he worked in the nuclear power industry and in automotive powertrain research and development. Mr MacDougall has extensive experience with international oilfield services company Schlumberger, with operational and management assignments in Australia, Asia, the UK North Sea, Europe, West Africa and the Middle East. Since 2001, he has been based in Australia, initially with independent Operator Stuart Petroleum as Production and Engineering Manager and subsequently as acting CEO prior to the takeover of Stuart Petroleum by Senex Energy. Mr MacDougall is an alumnus of Manchester University in the UK and of the INSEAD Business School in France. He is a member of the Society of Petroleum Engineers and also serves on the Advisory Board of the Australian School of Petroleum at Adelaide University. General Manager, Exploration and Subsurface Andrew Thomas BSc (Hons) Mr Thomas is a successful and experienced geoscientist who has been involved with Australian and International oil and gas exploration and development projects for over 29 years. He has experience in a wide range of onshore and offshore basins in Australia, Asia and Africa. Prior to joining Cooper Energy Mr Thomas was employed by Newfield Exploration in the roles of SE Asia New Ventures Manager and Exploration Manager for offshore Sarawak and was a key person in the team that successfully negotiated Newfield’s entry into Malaysia in 2004. Through the efforts of the teams he led, Newfield built a substantial portfolio of permits in Malaysia and made several significant oil and gas discoveries before being divested to SapuraKencana in 2014. Mr Thomas’s previous employers include Santos Limited, Gulf Canada and Geoscience Australia. He is a member of the American Association of Petroleum Geologists and a member of the Society of Petroleum Engineers. 33 Key Performance Indicators Operational Production 12 months to 30 June MMboe Proved and Probable reserves MMboe Wells drilled number Exploration wells spudded number 2012 2013 2014 2015 2016 2017 2018 2019 2020 0.52 1.88 10 6 0.49 2.16 13 8 0.59 2.01 11 5 0.48 3.08 9 4 0.46 3.00 1 - 0.96 11.7 9 1 1.49 52.4 4 2 1.31 52.7 0 0 1.56 49.9 18 4 Reserve replacement ratio1 percent (113)% 98% 71% 333% 18% 768% 2,380% (206)% (56)% Financial Sales revenue Other income EBITDA Profit before tax Profit after tax / (loss) Cash and term deposits Other financial assets Working capital Accumulated profit $ million $ million $ million $ million $ million $ million $ million $ million $ million Cumulative franking credits $ million 59.6 4.7 9.1 21.0 8.4 61.5 13.2 53.4 22.5 37.0 53.4 2.3 22.3 18.3 1.3 47.9 20.2 51.7 23.8 39.0 72.3 2.8 36.9 31.2 22.0 49.1 26.0 41.2 45.7 39.1 1.9 27.4 0.9 (58.4) (37.4) 39.1 1.6 1.9 (18.8) (26.0) (7.0) (63.5) (34.8) (12.3) 67.5 4.9 49.9 31.0 27.0 75.5 4.2 7.5 78.1 19.8 (75.2) (13.2) (110.0) (12.1) (86.0) 39.4 1.9 43.0 49.8 147.5 236.9 164.3 131.6 1.0 44.2 0.7 42.6 21.7 0.6 84.0 154.0 131.8 90.4 (17.7) (52.6) (64.9) (37.9) (49.9) (136.0) 38.7 43.7 42.9 91.6 42.9 42.9 42.9 42.9 285.0 443.9 433.7 351.1 Total equity $ million 136.9 137.2 167.8 103.9 Earnings per share cents 2.8 0.4 6.4 (19.2) (10.1) (1.8) 1.8 (0.7) (5.30) Return on shareholders funds percent 6.7% 0.9% 14.4% (46.7)% (38.0)% (6.5)% 7.4% (2.6)% (21.9)% Total shareholder return percent 25.0% (16.7)% 34.7% (51.5)% (12.2)% 72.7% 6.0% 40.3% (30.6)% Average oil price A$/bbl 114.63 112.31 124.08 85.48 60.75 61.89 99.61 106.19 83.75 Capital as at 30 June Share price Issued shares $ per share 0.45 0.375 0.505 0.245 0.215 0.38 0.385 0.54 0.375 million 327.3 329.1 329.2 331.9 435.2 1,140.2 1,601.1 1,621.6 1,621.6 Market capitalisation $ million 147.3 123.4 166.3 81.4 93.6 433.3 616.4 875.5 608.1 Shareholders number 5,485 5,284 5,122 5,103 4,931 6,292 6,622 6,758 8,094 1 Reserve replacement ratio calculated by net 1P reserve addition/production. 34 Cooper Energy Limited and its controlled entities Financial Report For the year ended 30 June 2020 Operating and Financial Review Directors’ Statutory Report Remuneration Report Consolidated Statement of Comprehensive Income Consolidated Statement of Financial Position Consolidated Statement of Changes in Equity Consolidated Statement of Cash Flows Notes to the Consolidated Financial Statements Group Performance 1. Segment reporting 2. Revenues and expenses 3. 4. Income tax Earnings per share Working Capital 5. Cash and cash equivalents and term deposits 6. Trade and other receivables 7. Prepayments 8. Inventory 9. Trade and other payables Capital Employed 10. Property, plant and equipment 11. Intangible assets 12. Exploration and evaluation assets 13. Oil and gas assets 14. Impairment 15. Provisions 16. Leases 17. Government grants Funding and Risk Management 18. Interest bearing loans and borrowings 19. Net finance costs 20. Contributed equity and reserves 21. Financial risk management 22. Hedge accounting Group Structure 23. Interests in joint arrangements 24. Investments in controlled entities 25. Parent entity information Other Information 26. Commitments for expenditure 27. Share based payments 28. Related party disclosures 29. Remuneration of Auditors 30. Events after the reporting period Directors’ Declaration Independent Auditor’s Report to the Members of Cooper Energy Limited Auditor’s Independence Declaration to the Directors of Cooper Energy Limited Securities Exchange and Shareholder Information 36 48 51 74 75 76 77 78 82 83 85 89 90 91 91 91 91 92 92 93 93 94 98 100 101 102 103 103 105 109 110 111 112 113 113 115 116 116 117 118 126 127 Abbreviations and Terms Corporate Directory Inside back over 128 3535 Operating and Financial Review For the year ended 30 June 2020 Operations Cooper Energy Limited (“Cooper Energy” or the “Company”) generates revenue from the supply of gas to south-east Australia and oil production in the Cooper Basin. The Group’s current operations and interests include: • offshore gas production in the Gippsland Basin, Victoria from the Sole gas field • offshore gas and gas liquids production in the Otway Basin, Victoria, from the Casino, Henry, Netherby (“Casino Henry”) gas fields; • non-operated onshore oil production and exploration from the western flank of the Cooper Basin; • the Athena Gas Plant (previously known as the Minerva Gas Plant) in the onshore Otway Basin; • the Manta gas and liquids field in the offshore Gippsland Basin; • the Annie gas discovery in the offshore Otway Basin; • exploration in the offshore and onshore Otway Basin; and • exploration in the offshore Gippsland Basin. The Company is the Operator of all of its offshore gas production, exploration and development activities and of the Athena Gas Plant. Reserves and Contingent Resources Proved and Probable Reserves (2P) as at 30 June 2020 are estimated at 49.9 million boe (barrels of oil equivalent) compared with 52.7 million boe at 30 June 2019. Contingent Resources (2C) as at 30 June 2020 are estimated at 34.9 million boe compared with 26.9 million boe at 30 June 2019. Details of reserves and resources and the movement from the previous year are available in the ASX announcement ‘Reserves and Contingent Resources Update’ of 31 August 2020. As at 30 June 20201 Gippsland Basin Otway Basin Cooper Basin Total Cooper Energy 2P Proved and Probable Reserves 2C Contingent Resource Gas PJ Oil & condensate MMbbl Total MMboe Gas PJ Oil & condensate MMbbl Total MMboe 237.5 57.8 0.0 295.3 0.0 0.0 1.6 1.6 38.8 9.4 1.6 49.9 134.8 49.4 0.0 184.2 3.4 0.1 0.8 4.4 25.5 8.5 0.8 34.9 1 As announced to the ASX on 31 August 2020. Totals may not reflect arithmetic addition due to rounding. The method of aggregation is by arithmetic sum by category. Workforce At 30 June 2020 the Company had 75.9 full time equivalent (FTE) employees and 31.5 FTE contractors compared with 53.5 full time equivalent (FTE) employees and 43.8 FTE contractors at 30 June 2019. The increase in employee numbers is attributable to resourcing the growth of the Group’s operations, including the acquisition of the Athena Gas Plant, and the shift of a number of contract staff to full time employment. Contractor numbers have fluctuated in line with the progress of both the Athena Gas Plant and the Sole Gas Project and requirements for the 2019 drilling program. Health Safety Environment and Community A single lost time injury occurred within the Company’s operations during the year. An employee of Diamond Offshore was injured on the Ocean Monarch drill rig in September while it was on location in VIC/P44, albeit not under the direction of the Company. The Company has been advised the injured worker has recovered and returned to work. Total recordable incident frequency rate for the period was 3.5 compared with zero for FY19. There were no reportable environmental incidents. Production Total production for the year was 1.56 million boe, 18% higher than the prior year’s 1.31 million boe, with the increase attributable to the Sole gas field. Gas production for the year was 8.3 PJ compared with 6.6 PJ in 2019. Significant features of the year’s production performance were the commencement of supply from Sole in March and the cessation of operations at the Minerva gas field in offshore Otway Basin in September. Sole produced a total of 2.1 PJ from the beginning of commissioning in March to 30 June. Liquids production for the year consisted of 196.2 kbbl compared with 242.5 kbbl in the previous year. Approximately 98% of the FY20 liquids production was sourced from the Cooper Basin, where production rates reflected natural decline. Commercial The Company’s strategy for creating shareholder value involves the development and operation of a portfolio style gas business to supply a tight south-east Australia domestic gas market. 36 Operating and Financial Review For the year ended 30 June 2020 Operations continued Fundamental to this strategy is the Company’s management of its gas production and sales contract portfolios. Cooper Energy seeks to produce gas from the most competitive sources of supply and to maintain a portfolio of contracts with blue-chip utility and industrial gas customers that support stable long-term production and optimisation of supply sourcing. Reliability of cash flow and earnings are prioritised through pricing, load factors and take-or-pay agreements that encourage stable sales through market and seasonal cycles. FY20 brought an unforeseen change in market cycle through the impact of the COVID-19 pandemic on energy demand and prices. The accounting impact of this is evident in the adjustments made to recognise the impact of the lower prevailing prices, and revised price expectations, for uncontracted gas and asset carrying values as at 30 June 2020. It is important to recognise these accounting adjustments hold no significance for the competitive position of the company’s gas, and its outlook which is discussed under the heading ‘Business strategies and prospects’ following. Furthermore, the merit of the company’s ‘long’ contract position whereby the majority of its proved and probable gas reserves are contract under agreed prices without energy price linkage. New gas contracts announced during the year included agreements with industrial gas users Visy and O-I Australia. The Sole gas field’s term contract capacity is now fully committed until 2025 (inclusive of extensions). Production from Casino Henry is fully contracted for the 2020 calendar year. Approximately 1 PJ of the Company’s share of production from Casino Henry in FY21 is contracted. Regional review Gippsland Basin The majority of the Company’s reserves, resources and anticipated production are attributable to the Gippsland Basin, offshore Victoria, Australia. Cooper Energy is the operator and 100% interest holder in all of its Gippsland Basin interests. These comprise: a) VIC/L32 which contains the Sole gas field; b) VIC/RL13, VIC/RL14 and VIC/RL15, which contain the Manta gas and liquids field. The Retention Leases also hold legacy infrastructure associated with the Basker Manta Gummy (“BMG”) oil project; c) VIC/RL16 which contains the shut-in Patricia-Baleen gas field, and infrastructure offering connection to the Orbost Gas Processing Plant; and d) exploration permits VIC/P72 and VIC/P75. Production First supply of gas from Sole occurred in March 2020 for the purposes of commissioning the Orbost Gas Processing Plant (owned and operated by APA Group “APA”). Commissioning of the plant continued for the remainder of the financial year, resulting in variable and intermittent production from the field. Sole supplied 2.1 PJ of gas into the Eastern Gas Pipeline during this period, all of which was sold on a spot basis under contract to utility gas customers. Sole Gas Project The Sole Gas Project involved development of the Sole gas field by Cooper Energy and upgrading of the Orbost Gas Processing Plant (OGPP) to process Sole gas by APA. The offshore project was completed within schedule, below budget and with zero lost time injuries and zero reportable environmental incidents after performance of 561,362 work hours at onshore, marine and subsea workplaces. Total capital cost for the offshore project was $335 million compared to the budget of $355 million. Commissioning of the plant upgrade is yet to meet the performance standards for completion, which includes demonstrated capacity to supply 68 TJ/day of Sole gas into the Eastern Gas Pipeline. As reported to the ASX, foaming in the absorber section of the plant has impaired output rates and been accompanied by fouling which required two shutdowns for maintenance prior to 30 June. The shutdowns and optimisation of operations by APA have resulted in improved plant performance. APA and Cooper Energy are working collaboratively to improve plant performance to that required for the completion of commissioning. Subsequent to year-end the two companies announced a Transition Agreement which establishes the commercial framework for this collaboration and progress towards the commencement of firm gas supply and the practical completion of the OGPP. Under the agreement revenue operating and capital costs will be shared while the OGPP proceeds to practical completion. Root cause analysis to identify the cause of the foaming, has been ongoing with involvement of the OGPP technology provider. APA has conducted minor plant modifications to improve performance, with further modifications planned for completion in September 2020. Planning is also underway for Phase 2 works to increase gas processing capacity, which will include the flexibility to reconfigure the two absorber vessels from a sequential to a parallel arrangement. The Phase 2 works (scope currently being finalised) are currently planned to commence in the December quarter (timing subject to supply chain and COVID-19 restrictions) for the resumption of production in the latter half of that quarter. If approved, it is expected the works would commence in the December quarter 2020 (timing subject to supply chain and COVID-19 restrictions) for the resumption of production in the latter half of that quarter. The cost of the Phase 2 works has not been finalised, with current estimates being $15 million (Cooper Energy share $7.5 million). 37 Operating and Financial Review For the year ended 30 June 2020 Operations continued Commencement of term gas supply contracts from Sole has been deferred until the earlier of January 2021 or when permitted by the commencement of firm supply from the OGPP. Whilst OGPP has demonstrated capability to maintain stable supply of 40-45 TJ/day, Cooper Energy and APA are working to establish firm supply capability from the plant in advance of practical completion. Development of Manta gas and liquids resource Development of the Manta gas and liquids field is being pursued as the next phase of the Gippsland gas development, utilising economies available through coordination with the Sole gas field development. Manta is assessed to contain Contingent Resources1 (2C) of 121 PJ of sales gas and 3.4 million barrels of condensate. A business case undertaken in 2015 affirmed the commercial potential of the field. Appraisal of the field’s Contingent Resources is considered necessary for confirmation of the assessed resource. An appraisal/exploration well, Manta-3, will also test the potential of a prospective resource in deeper reservoirs and inform a development decision on the field and the final firm development plan. The drilling of Manta-3 is being considered in the planning of the offshore drilling campaign expected to commence in FY23. Abandonment and remediation of BMG Planning for the abandonment of the BMG legacy oil infrastructure and lease remediation was advanced during the year with a view to FID and contracting of a well intervention vessel in the second half of FY21. Provisions for the performance of the abandonment have been reviewed and upgraded to reflect updates on costs and assessment of regulator expectations acquired during the year. It is expected the abandonment and remediation work would be completed in the 2023 calendar year subject to rig availability and regulatory approvals. Offshore Otway Basin The Company’s activities in the offshore Otway Basin comprise: a) offshore gas exploration, development and production i. production licences VIC/L24 and VIC/L30 containing the producing Casino, Henry and Netherby gas fields (“Casino Henry”); ii. production licences VIC/L33 and VIC/L34 containing part of the Black Watch gas field and Martha gas field; iii. exploration permit VIC/P44, which contains the undeveloped Annie gas discovery, and VIC/P76. All of these, except VIC/P76, are 50% interest held in joint ventures with Mitsui E&P Australia Pty Ltd and its associated entity Peedamullah Petroleum Pty Ltd (collectively referred to hereafter as “Mitsui”), operated by Cooper Energy. VIC/P76 is held 100% and operated by Cooper Energy. b) a 50% interest in and Operatorship of the Athena Gas Plant, onshore Victoria, which is jointly owned with Mitsui. The plant was acquired during the period to process gas from Casino Henry and other local discoveries such as Annie. c) a 10% interest in the production licence VIC/L22 which holds the Minerva gas field and is held in the Minerva Joint Venture with the Operator and remaining interest holder, BHP Petroleum. The field was shut-in during the period. Offshore Otway production Cooper Energy’s share of production from its offshore Otway interests was 1.0 million boe comprising 6.2 PJ of gas and 3,500 barrels of condensate. This is lower than the FY19 production of 1.1 million boe (6.6 PJ of gas and 4,600 barrels of condensate) due to the cessation of production from Minerva. Production from the Casino Henry field increased, reflecting higher production rates achieved following the resumption of production for repair and upgrade during the first quarter of the year. Offshore Otway exploration A two-well gas exploration program in the offshore Otway Basin was commenced in August 2019. The first well, Annie-1 in VIC/P44, made a new gas field discovery, identifying a gross 70 metre gas column in the primary target Waarre C formation with net gas pay thickness of 62 metres. A Contingent Resource assessment was issued to the ASX on 24 February and upgraded in the statement of reserves and resources issued 31 August 2020. Annie is assessed to hold gross 2C Contingent Resources of 57.4 PJ, with Cooper Energy’s equity share being 28.7 PJ. Development of the field is being assessed under the Otway Phase 3 Development Project discussed under Offshore Otway development following. Drilling of the second well in the program, Elanora-1 in VIC/L24, was deferred following repeated loss of tension on the mooring lines attached to the Ocean Monarch drilling rig whilst on location at Annie-1. Drilling of Elanora-1 will be considered for a drilling campaign being planned to commence in the latter half of 2022, subject to rig availability and joint venture approval. 1. Cooper Energy announced its assessment of the Manta Contingent Resource to the ASX on 12 August 2019. Cooper Energy is not aware of any new information or data that materially affects the information provided in that release and all material assumptions and technical parameters underpinning the assessment provided in the announcement continues to apply. 38 Operating and Financial Review For the year ended 30 June 2020 Operations continued The granting of the VIC/P76 permit during the year consolidated Cooper Energy’s offshore Otway acreage position around existing infrastructure and added to the exploration prospect inventory. The permit adjoins the Annie gas discovery and Casino production licence and is traversed by the Casino gas pipeline, which is to be connected to the Athena Gas Plant. Amplitude-supported prospects have been identified within the permit. Subsurface analysis of these prospects has commenced with a view to identifying the preferred candidate for drilling in the FY23 campaign. Offshore Otway development The Company is pursuing development opportunities to increase production, revenue generation and returns from the offshore Otway Basin: • upgrade and connection of the idle Athena Gas Plant to create a low-cost gas hub Cooper Energy, in joint venture with Mitsui, acquired the plant in December 2019 following the completion of operations at the depleted Minerva gas field. The plant offers improved resource recovery, lower processing costs and ullage for incremental gas production, such as from an additional development well at Henry or a new discovery such as Annie. Detailed engineering and design was conducted over the remainder of the year, culminating in Final Investment Decision being taken on the project in July 2020. The project involves upgrade of the plant and connection to the Company’s existing producing fields in the region for a gross projected construction cost of $37 million (Cooper Energy share 50%). Gross expenditure prior to FID on acquisition and FEED was $16 million. First gas into the plant is scheduled for the September quarter 2021, including allowances for COVID related disruptions as presently understood. • Otway Phase 3 Development Project The Otway Phase 3 Development Project (OP3D) involves development of the Annie gas field and infill drilling of the Henry gas field to enable production of approximately 100 PJ of gas via the Athena Gas Plant. OP3D is currently in the Concept Select phase. The project is scheduled to complete this phase in the September quarter 2020 which incorporates allowances for COVID-19 impacts as it is presently understood. It is possible further restrictions or supply chain disruption may cause delays to this schedule. Development drilling required for OP3D could be incorporated into the broader drilling rig program planned to commence in the second half of calendar 2022, enabling first gas from late in FY23. Onshore Otway Basin The Company’s interests in the onshore Otway Basin include licences in South Australia and permits in Victoria. Activities in the latter are currently suspended pursuant to the Petroleum Legislation Amendment Act which extends a Victorian State Government moratorium on onshore gas exploration until 30 June 2021. Conventional gas exploration in onshore Victoria can resume subsequent to that date. The onshore Otway Basin interests comprise: a) 30% interests in PEL 494, PRL 32 and PELA 680, South Australia. The remaining interest in these joint ventures is held by the Operator, Beach Energy Limited. At year-end advice was received from the South Australia government that a bid by Beach Energy Limited and Cooper Energy limited for block OT2019-B (renamed to PELA 680) was successful. It is expected the exploration permit will be awarded in late 2020. b) 50% interests in PEP 150 and PEP 168 in Victoria The remaining interests in the PEP 150 and PEP 168 joint ventures are held respectively by the Operators, Bridgeport Energy Limited and Beach Energy Limited. c) 75% interest in PEP 171 in Victoria, which may reduce to 50% on fulfilment of farm-in arrangements executed with Vintage Energy Ltd who hold 25% of the permit. An exploration well, Dombey-1, was drilled in PEL 494 during the year and recorded a new gas field discovery, identifying a gross gas column of 44.5 metres with net pay thickness of 25 metres in the primary target Pretty Hill formation. A production test recorded initial rates exceeding 18 MMscf/d indicating good reservoir productivity. Subsequent decline in flow rates, followed by re-pressurisation, suggests Dombey-1DW1 has drilled a small compartment partially connected to a broader accumulation. The results of Dombey-1 have affirmed the prospectivity of the onshore Otway Basin and de-risked a number of prospects within PEL 494. The joint venture is planning acquiring 3D seismic data to better understand the Dombey structure and adjacent prospects and better define the Dombey appraisal plans. Dombey-1 was part-funded through a $6.89 million PACE Gas Round 2 grant by the South Australian Government and is located 20 kilometres north-west of the Katnook Gas Plant. Cooper Basin The Cooper Basin interests comprise: a) 25% interest in PRLs 85-104 (the “PEL 92 Joint Venture”) with the remaining interest held by the Operator, Beach Energy Limited. b) 30% interest in PRLs 231-233 (the “PEL 93 Joint Venture”), with the remaining interest in the joint venture held by the Operator, Senex Energy Limited; 39 Operating and Financial Review For the year ended 30 June 2020 Operations continued c) 20% interest in PRL 237, with the remaining interests in the joint venture held by Metgasco Limited and the Operator, Senex Energy Limited; d) 19.165% interest in PRLs 207-209 (formerly PEL 100), with the remaining interests in the joint venture held by Santos QNT Pty Ltd and the Operator, Senex Energy Limited; and e) 20% interest in PRLs 183-190 (formerly PEL 110), with the remaining interest in the joint venture held by the Operator, Senex Energy Limited. Exploration and development A total of 16 wells were drilled by the PEL 92 Joint Venture during the year. The program included 13 appraisal wells, 1 development well and 2 exploration wells. Three appraisal wells were cased and suspended as future oil producers with all other wells being plugged and abandoned. Financial Performance Cooper Energy Limited recorded a statutory loss after tax of $86.0 million for the financial year which compares with the loss after tax of $12.1 million recorded in the 2019 financial year. The 2020 financial year statutory loss included a number of items which affected the result by a total of $79.4 million. These items comprise: • liquidated damages income of $19.8 million received from APA as a consequence of the delay to the commencement of gas production from the Orbost Gas Processing Plant; • a non-cash restoration expense of $14.1 million resulting from a reassessment of the Patricia Baleen field restoration provision and Minerva field restoration provision; • a non-cash impairment expense of $107.5 million; and • tax impact of the above items of $22.4 million The prior period result included a non-cash restoration expense of $26.2 million and a gain on exit provision of $0.8 million. Calculation of underlying net profit after tax by adjusting for items unrelated to the underlying operating performance is considered to provide a meaningful comparison of results between periods. Underlying net profit after tax and underlying EBITDAX are not defined measures under International Financial Reporting Standards and are not audited. Reconciliations of net (loss)/profit after tax, underlying net profit after tax, underlying EBITDAX and other measures included in this report to the Financial Statements are included at the end of this review. Underlying EBITDAX of $29.6 million was 14% lower than the prior comparative period figure of $34.3 million. This reduction has impacted underlying profit after tax in addition to the impact of increased depreciation and amortisation, exploration and evaluation expense and tax. The underlying loss after tax (exclusive of the items noted above) was $6.6 million, compared with an underlying profit after tax of $13.3 million in the 2019 financial year. The factors which contributed to the movement between the periods were: • higher gas sales revenue of $2.6 million attributed to Sole gas sales, improved performance of the Casino Henry wells and higher contracted gas prices. This was partially offset by decline in oil sales volumes and price; • higher costs of sales of $11 million; largely due to non-cash factors. Amortisation and depreciation was $8.5 million higher primarily due to increases in future development costs of undeveloped proved and probable reserves and early cessation of the Minerva Field. Gas processing costs and royalties were $2.5 million higher; • higher net finance costs of $4.3 million due to cessation of interest capitalised on the Sole Oil and Gas asset; • higher care and maintenance costs of $3.0 million and other costs of $2.8 million; and • higher exploration and evaluation write off of $1.7 million attributable to unsuccessful wells in the Cooper Basin and costs associated with the deferred Elanora well in the offshore Otway basin. Financial Performance FY20 FY19 Change Sales volume Sales revenue Gross profit Gross profit / Sales revenue Operating cash flow Cash, other financial assets and investments Reported loss after tax Underlying (loss)/profit after tax Underlying (loss)/profit before tax Underlying EBITDAX* MMboe $ million $ million % $ million $ million $ million $ million $ million $ million 1.5 78.1 23.6 30.2 48.1 132.1 (86.0) (6.6) (30.5) 29.6 1.3 75.5 31.7 42.0 20.5 165.5 (12.1) 13.3 12.1 34.3 0.25 2.6 (8.1) (11.8) 27.6 (33.4) (73.9) (19.9) (42.6) (4.7) * Earnings before interest, tax, depreciation, amortisation, restoration, exploration and evaluation expense and impairment % 19% 3% (25%) (28%) 134% (20%) (611%) (150%) (352%) (14%) 40 Operating and Financial Review For the year ended 30 June 2020 Financial Performance continued All numbers in tables in the Operating and Financial Review have been rounded. As a result, some total figures may differ insignificantly from totals obtained from arithmetic addition of the rounded numbers presented. Cash and cash equivalents balance decreased by $32.7 million over the period as summarised in the following chart. Operating cashflows for the period were $48.1 million comprising: • cash generated from operations of $40.3 million; • liquidated damages of $19.8 million received as a consequence of the delay to the commencement of gas production from the Orbost Gas Processing Plant disclosed as a significant item above; • general administration costs of $11.3 million; • restoration costs of $2.5 million; • Petroleum Resource Rent Tax (PRRT) receipts of $4.1 million as a result of transferable exploration credits; and • net interest paid of $2.3 million; Financing, investing and other cash flows for the period were $80.8 million and included: • debt drawdowns of $11.0 million; • interest payments of $9.7 million; • exploration, development and property, plant and equipment costs of $81.7 million, mainly in relation to the drilling of Annie-1, Dombey-1, and Cooper Basin appraisal wells. Other items in this category included payments made on the Minerva Gas Plant acquisition and for the Sole Gas Project; and • foreign exchange differences and other of $0.4 million. $ million Total cash and cash equivalents, other financial assets and investments 165.5 Other financial assets and investments 40.3 1.2 164.3 Cash and cash equivalents Movements in cash and cash equivalents 2020 vs 2019 +113.6 19.8 (11.3) (2.5) 4.1 (2.3) (11.0) (9.7) Total cash and cash equivalents, other financial assets and investments 132.2 (81.7) Other financial assets and investments (0.4) 0.6 212.4 131.6 Cash and cash equivalents Operating 48.1 Other (80.8) June -19 Operations Liquidated damages General admin Restoration costs PRRT Net Interest Cash after operating cash flows Net debt draw- downs Interest payments E & D FX & Other June-20 41 Operating and Financial Review For the year ended 30 June 2020 Financial Position Financial Position Total assets Total liabilities Total equity Net debt Assets $ million $ million $ million $ million FY20 1,029.9 678.8 351.1 97.8 FY19 1,001.8 568.1 433.7 53.9 Change 28.1 110.7 (82.6) 43.9 % 3% 19% (19%) 81% Total assets increased by $28.1 million from $1,001.8 million to $1,029.9 million. At 30 June the Company held cash and cash equivalents of $131.6 million and investments of $0.6 million. Exploration and evaluation assets increased by $6.8 million from $152.3 million to $159.1 million as a result of increases associated with the reset of the rehabilitation provisions and capital expenditure incurred on exploration assets, offset by impairment within the BMG, VIC/P44, PEL 92 and the Onshore Otway permits. Oil and gas assets increased by $2.8 million from $613.2 million to $616.0 million mainly as a result of capital expenditure incurred on development activities and increases associated with the reset of the rehabilitation provisions, offset by impairment on Casino Henry. The impairments arose from review of asset carrying values and provisions in light of lower gas and oil prices in post-COVID-19 markets and intelligence acquired during the year on drilling, development and restoration and abandonment costs. The review incorporated revised assumptions for oil and gas prices and exchange rates based on current and expected values. Price assumptions for uncontracted gas have been revised to reflect expectations as at June 2020 for future term gas sales. Total Liabilities Total liabilities increased by $110.7 million from $568.1 million to $678.8 million. Provisions increased by $106.7 million from $287.9 million to $394.6 million attributable to the revised gross cost assumptions for restoration provisions and lower discount rates. Interest bearing loans and borrowings increased by $15.7 million from $213.7 million to $229.4 million. This represents the drawdowns under the reserve-based lending (RBL) facility. Total Equity Total equity decreased by $82.6 million from $433.7 million to $351.1 million. In comparing equity at 30 June 2020 to 30 June 2019 the key movements were: • higher contributed equity of $1.5 million due to shares issued on vesting of performance rights and share appreciation rights during the period; • higher reserves of $1.9 million mainly due to the vesting of equity incentives to employees partially offset by fair value movements in the Company’s interest rate swaps for which cash flow hedge relationships apply; and • higher accumulated losses of $86.0 million due to the statutory loss for the period. Outlook The Company expects substantially increased production and sales in the 12 months to 30 June 2021 as a result of a full year contribution from the Sole gas field. The extent of this increase will depend upon the timing and rate of build-up of production at the Orbost Gas Processing Plant, which is still undergoing commissioning. As an indication, the total production from all operations in FY20 averaged 4.275 kboe/day. This compares to approximately 6.5 to 7 kboe/day from Sole alone at the rate of approximately 40 - 45 TJ/day maintained by the plant in late June to early July 2020. Achievement of plant nameplate capacity represents an increment to these rates of 23 TJ to 28 TJ/day, or another 3.7 to 4.5 kboe/day. This goal is being pursued by the ongoing optimisation of operations and Phase 2 plant works being planned by APA and Cooper Energy as discussed earlier under the heading ‘Sole Gas Project’. Ongoing technical analysis on the cause of the foaming within the plant (discussed on page 37) may also identify avenues for improvement of plant performance. The average daily rates over the course of the year may be affected by shutdowns for modifications or maintenance. Other operations are expected to contribute approximately 2.6 kboe/day in FY21. Gas production of between 4 to 5 PJ is anticipated from the offshore Otway (6 PJ in FY20), lower than FY20 due to the impact of shutdowns for maintenance of the Iona Gas Plant and, later in the year, for connection to the Athena Gas Plant. Crude oil production from the Cooper Basin of 0.2 million barrels is expected (0.2 million barrels in FY20). Capital expenditure of between $50 million and $58 million is anticipated in FY21 with plans concentrated on the offshore Otway operations, most particularly the Athena Gas Project. It is intended to progress the OP3D and Manta-3 projects through the Select stage and towards FID by the conclusion of FY21. The results of this work, together with well planning and subsurface studies on exploration targets in the Otway and Gippsland Basins is expected to determine the composition of an offshore drilling program planned to commence, subject to rig availability in the first half of FY23. Two development wells are planned for the Cooper Basin. 42 Operating and Financial Review For the year ended 30 June 2020 Business Strategies and Prospects Two premises underly the Company’s gas strategy: first, south-east Australia will require new sources of gas supply to replace declining production from existing sources; and second, the most competitive source of supply for the region is gas produced in the region. Accordingly, the Company’s strategy for the generation of shareholder wealth entails ownership and operation of a portfolio of gas assets with superior competitiveness for the supply opportunities foreseen in south-east Australia. To this end, the Company has accumulated a portfolio of gas assets occupying favourable positions on the cost curve for delivered gas to its markets and a portfolio of supply contracts with utility and industrial customers. FY20 saw short term disruption to energy market supply balances and a reaffirmation of the medium to long term merit of the Company’s strategy and asset portfolio. The surplus of international LNG supply relative to demand and lower economic activity levels during the year resulted in increased availability of gas and lower spot prices. This situation has continued into FY21. Analysis by the Company and by the Australian Energy Market Operator has reaffirmed the premise of the Company’s gas strategy, anticipating a widening gap between local demand and depleting local supply from FY22 onwards. The Company is well-positioned for both the near and longer terms by virtue of its gas contract portfolio and the competitiveness of its asset base in comparison with other potential sources of supply. The Company’s contracted gas is committed under take-or-pay terms, without oil price linkage, to provide assurance of cash flow. Looking to the longer term, the Company expects to generate wealth through supplying into an increasingly tight south-east Australian gas market from its uncontracted reserves, resources and that identified through exploration. During FY21 and FY22 the Company anticipates executing business plans to increase its exposure to the favourable south-east Australian gas market anticipated in the medium term. These plans include: • the Athena Gas Plant project. Apart from establishing a low-cost processing hub for Otway Basin gas, the project will permit gas from Casino Henry to be contracted on a firm supply basis; • definition of an economic development project for undeveloped gas in the Henry and Annie gas fields through the OP3D project; • commitment to the drilling of the Manta-3 appraisal and exploration well. Development of Manta is contingent on the outcomes of the Manta-3 well; and • identification of preferred targets for exploration for new resources of gas in the Otway and Gippsland basins. The Company’s acreage in these regions holds identified gas prospects in proximity, and on-trend with, producing and known gas fields and close to existing pipe and processing infrastructure. These are to be targeted in the drilling campaign being planned for FY23. The Company is vigilant in identifying potential value-creation opportunities from participation in assets that fit with the Company’s capabilities, strategy and portfolio. The Company reviews its portfolio and equity participation levels on an ongoing basis for optimal allocation of capital for value creation. Funding and Capital Management Cooper Energy seeks to manage its capital with the objective of providing shareholders with the optimal risk-weighted return from the application of its expertise in the exploration, development, production and sale of hydrocarbons. At 30 June 2020 the Company had cash, deposits, and equity instruments of $131.6 million and drawn debt of $229.4 million. The Company has a Reserve Based Lending facility to fund a portion of the Sole gas field development with a limit of $250.0 million. Of this limit, $233.0 million is available, of which $3.6 million remains undrawn at 30 June 2020. The facility can be used for general corporate purposes after project completion. The Company has additional liquidity of approximately $15.0 million through a working capital facility to be used for general business purposes, of which $1.5 million has been utilised in respect of bank guarantees with the remaining balance undrawn. Further information is detailed in the Going concern basis section on page 78 and Note 18 of the Financial Statements. The Company continues to assess value accretive funding options as it pursues growth opportunities. Risk Management The Company manages risks in accordance with its risk management policy with the objective of ensuring risks inherent in oil and gas exploration and production activities are identified, measured and then managed or kept as low as reasonably practicable. The Executive Leadership Team perform risk assessments on a regular basis and a summary is reported to the Risk and Sustainability Committee. The Committee approves and oversees an internal audit program undertaken internally and/or in conjunction with appropriate external industry or field specialists. COVID-19 Cooper Energy responded to the COVID-19 pandemic in line with its focus on: • prioritising the safety and welfare of its employees and their families, together with that of contractors, suppliers and the communities within which it operates. • assessing, monitoring and managing risks to the continuity of the business. 43 Operating and Financial Review For the year ended 30 June 2020 Risk Management continued A Pandemic Response Team was established and resourced to include input from an independent medical practitioner, reporting to the Managing Director to oversee the company’s response. That response included implementing robust work from home arrangements with on-site staffing requirements limited to minimal IT support attendance when required at office locations and a skeleton staff at the Cooper Energy operated Athena Gas Plant. The work from home arrangements were used in Adelaide and Perth during the period March – May 2020, and contingencies are in place to rapidly reinstate them if required. The Athena Gas Plant upgrade continues with limited on-site manning and specific risk controls in place. All of the company’s gas production is via unmanned subsea installations, which are operated remotely via the relevant plant onshore control room. Accordingly, transitioning the company into and out of work from home has had no impact on production levels. Emergency response procedures were tested using fully remote processes during the period. The COVID-19 pandemic has been assessed as not being among the Company’s key corporate risks, however it has affected the business indirectly through the impact on energy prices, supply chains and through restrictions on travel. The Pandemic Response Team continues to monitor and advise the Managing Director and Executive Leadership Team on ongoing potential COVID-19-related threats to the business and appropriate preventative actions and responses to the pandemic. Appropriate policies and procedures are continually being developed and updated to manage these risks. Risk Description Exploration Development and Production Regulatory Market 44 Exploration is a speculative activity with an associated risk of discovery to find oil and gas in commercial quantities and a risk of development. If Cooper Energy is unsuccessful in locating and developing or acquiring new reserves and resources that are commercially viable, this may have a material adverse effect on future business, results of operations and financial conditions. Cooper Energy utilises established methodologies and experienced personnel to evaluate prospects and manage the risk associated with exploration. The Company also ensures all major exploration decisions are subjected to assurance reviews which include external experts and contractors where appropriate. Development and production of oil and gas projects may be exposed to low side reserve outcomes, cost overruns, production decrease or stoppage, which may result from facility shutdowns, mechanical or technical failure and other unforeseen events. Cooper Energy undertakes technical, financial, business and other analysis in order to determine a project’s readiness to proceed from an operational, commercial and economic perspective. Even if Cooper Energy recovers commercial quantities of oil and gas, there is no guarantee that a commercial return can be generated. All major development investment decisions are subjected to assurance reviews which includes external experts and contractors where appropriate. Cooper Energy operates in a highly regulated environment and complies with regulatory requirements. There is a risk that regulatory approvals are withheld, take longer than expected or unforeseen circumstances arise where requirements may not be adequately addressed in the eyes of the regulator and costs may be incurred to remediate non-compliance and/or obtain approval(s). Changes in personnel, Government, monetary, taxation and other laws in Australia or internationally may impact the Company’s operations. Cooper Energy monitors legislative and regulatory developments and works to ensure that stakeholder concerns are addressed fairly and managed. Documents submitted to regulatory authorities are reviewed and audited to help ensure they are appropriate and comply with all regulatory requirements. The global oil market and Australian domestic gas market are subject to fluctuations of demand and supply and as a consequence price. The risk of material changes to the demand for oil and gas produced by the Company’s business exists from sources such as demand destruction, changes in energy consumption preferences and demand and supply-side disruption such as an expansion of alternative, competitive supply sources. If realised, these may result in reduced sales volume and sales revenue with consequent impact on the efficiency of operations and the Company’s financial condition. In the near term this risk is managed through its gas contracting strategy. The Company maintains ‘long’ contract coverage such that the major share of its available reserves is contracted, typically under gas sales agreements with a term of at least 4 years. Stability of cash flow is protected through terms which encourage reliable demand from customers and which include take-or-pay clauses to ensure minimum annual cash flows. Uncontracted gas carries exposure to favorable or unfavourable price movements. The greater share of the Company’s uncontracted gas is in the offshore Otway Basin where the Athena Gas Plant Project is being conducted to facilitate the securing of longer term contracts supported by more favourable processing terms. Cooper Energy monitors developments and changes in the international oil and domestic gas market to enable the Company to be best placed to address changes in market conditions. This activity includes ongoing research and analysis of future demand and supply for energy, most particularly gas, in its market of south-east Australia. The Company’s portfolio management and investment strategy expressly focus on assets with a foreseeable pathway to commercialisation within the medium term to remove the risk of exposure to assets becoming stranded by unforeseen developments in long term investment horizons. Operating and Financial Review For the year ended 30 June 2020 Risk Management continued Risk Description Oil and gas prices Future value, growth and financial conditions are dependent upon the prevailing prices for oil and gas. Prices for oil and gas are subject to fluctuations and are affected by numerous factors beyond the control of Cooper Energy. Cooper Energy monitors and analyses the oil and gas markets and seeks to reduce price risk where reasonable and practical. The Company has policies and procedures for entering into hedging contracts to mitigate against the fluctuations in oil price and exchange rates. Gas price risk is assessed within the context of the Company’s ongoing modelling of the south-east Australian energy market and through its gas contracting strategy which prioritises long term agreements and appropriate indexation and price review clauses. Operating There are a number of risks associated with operating in the oil and gas industry. The occurrence of any event associated with these risks could result in substantial losses to the Company that may have a material adverse effect on Cooper Energy’s business, results of operations and financial condition. To the extent that it is reasonable to do so, Cooper Energy mitigates the risk of loss associated with operating events through insurance contracts. Cooper Energy operates with a comprehensive range of operating and risk management plans (updated in FY20 to reflect risks associated with COVID-19) and an HSEC management system to ensure safe and sustainable operations. Counterparties The ability of Cooper Energy to achieve its stated objectives will depend on the performance of the counterparties under various agreements it has entered into (including joint venture arrangements). If any counterparties do not meet their obligations under the respective agreements, this may impact on operations, business and financial conditions. Reserves Cooper Energy monitors performance across material contracts against contractual obligations to minimise counterparty risk and seeks to include terms in agreements which mitigate such risks. The Company’s gas contracting strategy expressly focusses on financially robust organisations assessed as being reliable gas consumers within the energy markets forecast by the Company’s, and third party, research. Oil and gas reserves are expressions of judgement based on knowledge, experience and industry practice. These estimates may alter significantly or become uncertain when new information becomes available and/or there are material changes of circumstances which may result in Cooper Energy altering its plans which could have a positive or negative effect on Cooper Energy’s operations. Reserves and Contingent Resources estimation is consistent with the definitions and guidelines in the Society of Petroleum Engineers (SPE) 2018 Petroleum Resources Management System (PRMS). The assessment of Reserves and Contingent Resources may also undergo independent review. Environment Cooper Energy’s exploration, development and production activities are subject to state, national and international environmental laws and regulations. Oil and gas exploration, development and production can be potentially environmentally hazardous giving rise to substantial costs for environmental rehabilitation, damage control and losses. Funding Restoration liabilities Cooper Energy has a comprehensive approach to the management of risks associated with environment which is embedded as a core part of our approach to health, safety, environment and community. This approach includes standards for asset reliability and integrity, technical and operational competency and emergency response preparedness. Cooper Energy must undertake significant capital expenditures in order to conduct its development appraisal and exploration activities. Limitations on the access to adequate funding could have a material adverse effect on the business, results from operations, financial conditions and prospects. Cooper Energy’s business and, in particular development of large scale projects, relies on access to debt and equity funding. There can be no assurance that sufficient debt or equity funding will be available on acceptable terms or at all. Cooper Energy endeavours to ensure the best source of funding is obtained to maximise shareholder value, having regard to prudent risk management supported by economic and commercial analysis of all business undertakings. Cooper Energy has certain obligations in respect of decommissioning of its fields, production facilities and related infrastructure. These liabilities are derived from legislative and regulatory requirements concerning the decommissioning of wells and production facilities and require Cooper Energy to make provisions for such decommissioning and the abandonment of assets. Provisions for the costs of this activity are informed estimates and there is no assurance that the costs associated with decommissioning and abandoning will not exceed the amount of long-term provisions recognised to cover these costs. Cooper Energy recognises restoration provisions after construction and conducts a review on a semi-annual basis. Any changes to the estimates of the provisions for restoration are recognised in line with accounting standards. 45 Operating and Financial Review For the year ended 30 June 2020 Risk Management continued Risk Description Community Cooper Energy conducts exploration and production operations in regions with residential, environmental, cultural and economic significance to local and national communities. Loss of confidence in the Company, in its ability to operate responsibly or opposition to exploration and production activities generally within these communities may adversely affect community sentiment towards Cooper Energy and impact its capacity to execute its plans. Cooper Energy conducts a community engagement programme at multiple levels and in multiple forms. The purpose of this programme is to build and maintain awareness, understanding and support of the Company, its operations and plans in the local regions. It serves to build long term positive relationships with local communities together with awareness of the economic benefits to the community and the nation generally. Elements of the program include: • • • • sponsorship and donations made to local community organisations; engagement and briefing with local office holders and elected representatives of local, state, and federal government. engagement with local community groups via town hall meetings and community information sessions; engagement with fishing industry associations; • publication of information regarding the Company’s activities and plans including the maintenance of a ‘Community’ page on the Company’s website; and • engagement with local media, including the use of social media. Climate and Sustainability Cooper Energy recognises that direct physical and indirect non-physical impacts of climate change may affect our operations and the markets into which we sell our gas and oil. Potential risks include those arising from increased severe weather events; longer-term changes in climate patterns; sea level rise; and increased frequency and severity, of bushfires. Indirect risks arise from a variety of legal, policy, technology, and market responses to the challenges that climate change poses as society transitions to a lower emissions future. These risks may impact the demand for and competitiveness of the Company’s products and the Company’s appeal as an investment, employer, and community member. Assessment and response to these risks is undertaken on three fronts: 1) understanding, managing and mitigating the risks presented by direct physical impacts 2) understanding, managing and mitigating the impact of climate change and emissions policy on the demand for the Company’s products (“market risk”) 3) identification of means by which the Company can reduce its direct emissions and lessen its overall emissions impact. In respect of market risk, the Company’s expressed investment strategy means its gas assets possess a low exposure to the possibility of demand loss from climate change. A favourable market for sale of the Company’s gas reserves and resources has been confirmed and is expected to continue given demand and supply forecasts for its chosen market of south-east Australia and the role gas is expected to play as a conventional and transition energy source in a lower emissions world. The Company’s portfolio of gas assets is concentrated in south-eastern Australia and reflects its screening criteria which requires superior cost competitiveness in delivered gas and a foreseeable pathway to development. Australian government forecasts (Australian Energy Market Operator; AEMO) project a widening gap between gas demand and supply in south-east Australia. Production from the region’s existing sources of supply is projected to decline significantly over the coming 10 years. The merits of gas as a clean-burning energy source, and as a necessary backstop of dispatchable power for renewable energy, are expected to support greater use of gas compared with other fossil fuels. Gas is expected to continue to be a principal source of energy for conventional heating and cooking applications and a critical input for industrial uses including fertiliser and other agricultural chemicals, refrigerants, plastics, glass manufacture, food processing and pharmaceuticals. Natural gas is viewed as a key element supporting society’s sustainable energy transition and forecasts show an increasing global demand for gas over the medium to long term. The Company measures and reports its emissions in its annual Sustainability Report (the first of which was published in October 2019). The focus of the Company’s strategy on conventional gas production, located in south-east Australia close to its market in south-east Australia, is conducive to lower emissions gas supply. The Company measures, monitors and reports on its emissions and seeks to reduce its emissions impact. These results are published in its annual Sustainability Report. 46 Operating and Financial Review For the year ended 30 June 2020 Reconciliations for net profit/(loss) to Underlying net profit/(loss) and Underlying EBITDAX Reconciliation to Underlying profit/(loss) Net profit/(loss) after income tax Adjusted for: Gain on exit provision Liquidated damages Restoration expense Impairment Tax impact of underlying adjustments Underlying (loss)/profit Reconciliation to Underlying EBITDAX* Underlying (loss)/profit Add back: Tax impact of underlying adjustments Net interest expense/(revenue) Accretion expense Tax expense Depreciation Amortisation Exploration and evaluation expense Underlying EBITDAX* $ million $ million $ million $ million $ million $ million $ million $ million $ million $ million $ million $ million $ million $ million $ million $ million FY20 (86.0) - (19.8) 14.1 107.5 (22.4) (6.6) FY20 (6.6) 22.4 1.8 4.0 (23.9) 2.3 26.5 3.1 29.6 FY19 (12.1) Change % (73.9) (611%) (0.8) - 26.2 - - 13.3 FY19 13.3 - (3.4) 5.0 (1.2) 1.0 18.2 1.4 34.3 0.8 (19.8) (12.1) 107.5 (22.4) (19.9) 100% (100%) (46%) 100% (100%) (150%) Change % (19.9) (150%) 22.4 5.2 (1.0) (22.7) 1.3 8.3 1.7 (4.7) 100% 153% (20%) (1892%) 130% 46% 121% (14%) * Earnings before interest, tax, depreciation, amortisation, restoration, exploration and evaluation expense and impairment The adoption of AASB 16 Leases in the period means that the FY20 results have a higher portion of depreciation and interest charge and lower SG&A costs. This increases the current year EBITDAX by $1.7 million relative to the prior year. 47 Directors’ Statutory Report For the year ended 30 June 2020 The Directors present their report together with the Consolidated Financial Report of the Group, being Cooper Energy Limited (the “parent entity” or “Cooper Energy” or “Company”) and its controlled entities, for the financial year ended 30 June 2020, and the Independent Auditor’s Report thereon. 1. Directors The Directors of the parent entity at any time during or since the end of the financial year are: Mr John C. Conde AO B.Sc. B.E(Hons), MBA Chairman Independent Non-Executive Director Appointed 25 February 2013 Mr David P. Maxwell M.Tech, FAICD Managing Director Appointed 12 October 2011 Mr Timothy G. Bednall LLB (Hons) Independent Non-Executive Director Appointed 31 March 2020 subject to confirmation by shareholders at the Company’s 2020 AGM 48 Experience and expertise Mr Conde has extensive experience in business and commerce and in chairing high profile business, arts and sporting organisations. Previous positions include Non-Executive Director of BHP Billiton, Chairman of Pacific Power (the Electricity Commission of NSW), Chairman of the Sydney Symphony Orchestra, Director of AFC Asian Cup, Chairman of Events NSW, President of the National Heart Foundation and Chairman of the Pymble Ladies’ College Council. Current and other directorships in the last 3 years Mr Conde is Chairman of The McGrath Foundation (since 2013 and Director since 2012). He is President of the Commonwealth Remuneration Tribunal (since 2003) and a Director of Dexus Property Group ASX: DXS (since 2009). He is Deputy Chairman of Whitehaven Coal Limited ASX: WHC (since 2007). Mr Conde is a former Chairman of Bupa Australia (2008 – 2018). Special responsibilities Mr Conde is Chairman of the Board of Directors. He is also a member of the People and Remuneration Committee and is the Chairman of the Nomination Committee. Experience and expertise Mr Maxwell is a leading oil and gas industry executive with more than 25 years in senior executive roles with companies such as BG Group, Woodside Petroleum Limited and Santos Limited. Mr. Maxwell has very successfully led many large commercial, marketing and business development projects. Prior to joining Cooper Energy Mr Maxwell worked with the BG Group, where he was responsible for all commercial, exploration, business development, strategy and marketing activities in Australia and led BG Group’s entry into Australia and Asia including a number of material acquisitions. Mr Maxwell has served on a number of industry association boards, government advisory groups and public company boards. Current and other directorships in the last 3 years Mr Maxwell is a Director of wholly owned subsidiaries of Cooper Energy Limited. He is also on the Board of the Australian Petroleum Production & Exploration Association (since 2018) and the Minerals and Energy Advisory Council (since 2019). Special responsibilities Mr Maxwell is Managing Director. He is responsible for the day to day leadership of Cooper Energy, and is the leader of the Executive Leadership Team. Mr Maxwell is also chairman of the HSEC Committee (being a management committee, not a Board committee). Experience and expertise Mr Bednall is a highly experienced and respected corporate lawyer and law firm manager. He is a partner of King & Wood Mallesons (KWM), where he specialises in mergers and acquisitions, capital markets and corporate governance, representing public company and government clients. Mr Bednall has advised clients in the oil and gas and energy sectors throughout his career. Mr Bednall was the Chairman of the Australian partnership of KWM from January 2010 to December 2012, during which time the merger of King & Wood and Mallesons Stephen Jaques was negotiated and implemented. He was also Managing Partner of M&A and Tax for KWM Australia from 2013 to 2014, and Managing Partner of KWM Europe and Middle East from 2016 to 2017. He was General Counsel of Southcorp Limited (which became the core of Treasury Wine Estates Limited) from 2000 to 2001. Current and other directorships in the last 3 years Mr Bednall is a board member of the National Portrait Gallery Foundation (since 2018). Special responsibilities Mr Bednall is a member of the People & Remuneration Committee, the Nomination Committee and the Risk & Sustainability Committee. Director’s Statutory Report For the year ended 30 June 2020 1. Directors continued Ms Victoria J. Binns B. Eng (Mining – Hons 1), Grad Dip SIA, FAusIMM, GAICD Independent Non-Executive Director Appointed 2 March 2020 subject to confirmation by shareholders at the Company’s 2020 AGM Ms Elizabeth A. Donaghey B.Sc., M.Sc. Independent Non-Executive Director Appointed 25 June 2018 Experience and expertise Ms Binns has over 35 years’ experience in the global resources and financial services sectors including more than 10 years in executive leadership roles at BHP and 15 years in financial services with Merrill Lynch Australia and Macquarie Equities. During her career at BHP, Ms Binns’ roles included Vice President Minerals Marketing, leadership positions in the metals and coal marketing business, Vice President of Market Analysis and Economics and was a member of the first BHP Global Inclusion and Diversity Council. Prior to joining BHP, Ms Binns held a number of board and senior management roles at Merrill Lynch Australia including Managing Director and Head of Australian Research, Head of Global Mining, Metals and Steel, and Head of Australian Mining Research. She was also co-founder and Chair of Women in Mining and Resources Singapore. Current and other directorships in the last 3 years Ms Binns is currently a Non-Executive Director of ASX-listed company Evolution Mining (since 2020). Special responsibilities Ms Binns is a member of the Audit Committee, the People & Remuneration Committee and the Risk and Sustainability Committee. Experience and expertise Ms Donaghey brings over 30 years’ experience in the energy sector including technical, commercial and executive roles in EnergyAustralia, Woodside Energy and BHP Petroleum. Ms Donaghey’s experience includes Non-Executive Director roles at Imdex Ltd (an ASX-listed provider of drilling fluids and downhole instrumentation), St Barbara Ltd (a gold explorer and producer), and the Australian Renewable Energy Agency. She has performed extensive committee roles in these appointments, serving on audit and compliance, risk and audit, technical and regulatory, remuneration and health and safety committees. Current and other directorships in the last 3 years Ms Donaghey is a Non-Executive Director of the Australian Energy Market Operator (AEMO) (since 2017). Special responsibilities Ms Donaghey is a member of the Risk and Sustainability Committee, the People and Remuneration Committee and the Nomination Committee. Mr Hector M. Gordon B.Sc. (Hons) Independent Non-Executive Director 26 June 2012 – 23 June 2017 Non-Executive Director Appointed 24 June 2017 Experience and expertise Mr Gordon is a geologist with over 40 years’ experience in the upstream petroleum industry, primarily in Australia and southeast Asia. He joined Cooper Energy in 2012, initially as an Executive Director – Exploration & Production and subsequently moved to his position as Non-Executive Director in 2017. Mr Gordon was previously Managing Director of Somerton Energy until it was acquired by Cooper Energy in 2012. Previously he was an Executive Director with Beach Energy Limited where he was employed for more than 16 years. In this time Beach Energy experienced significant growth and Mr Gordon held a number of roles including Exploration Manager, Chief Operating Officer and, ultimately, Chief Executive Officer. Current and other directorships in the last 3 years Mr Gordon is a Director of Bass Oil Limited ASX: BAS (since 2014). Special responsibilities Mr Gordon is the Chairman of the Risk and Sustainability Committee and a member of the Audit Committee. Mr Jeffrey W. Schneider B.Com Independent Non-Executive Director Experience and expertise Mr Schneider has over 30 years of experience in senior management roles in the oil and gas industry, including 24 years with Woodside Petroleum Limited. He has extensive corporate governance and board experience as both a Non-Executive Director and chairman in resources companies. Appointed 12 October 2011 Current and other directorships in the last 3 years Mr Schneider does not currently hold any other directorships. Special responsibilities Mr Schneider is Chairman of the People and Remuneration Committee, and a member of the Nomination Committee and the Audit Committee. 49 Director’s Statutory Report For the year ended 30 June 2020 1. Directors continued Ms Alice J. Williams B.Com, FAICD, FCPA, CFA Independent Non-Executive Director Appointed 28 August 2013 Experience and expertise Ms Williams has over 30 years of senior management and Board level experience in corporate, investment banking and Government sectors. Ms Williams has been a consultant to major Australian and international corporations as a corporate advisor on strategic and financial assignments. Ms Williams has also been engaged by Federal and State based Government organisations to undertake reviews of competition policy and regulation. Prior appointments include Director of Airservices Australia, Guild Group, Port of Melbourne Corporation, Telstra Sale Company, V/Line Passenger Corporation, State Trustees, Western Health and the Australian Accounting Standards Board. Ms Williams is also a former council member of the Cancer Council of Victoria. Current and other directorships in the last 3 years Ms Williams is a Non-Executive Director of Equity Trustees Ltd ASX: EQT (since 2007), Djerriwarrh Investments Ltd, Defence Health (since 2010) and not for profit Tobacco Free Portfolios (since 2018). Ms Williams has recently stepped down as a Member of the Foreign Investment Review Board. Ms Williams was a Non-Executive Director of the Victorian Funds Management Corporation for the period 2008 to 2018. Special responsibilities Ms Williams is the Chairman of the Audit Committee and a member of the Risk and Sustainability Committee. 2. Company secretary Ms Amelia Jalleh B.A., LLB (Hons), LLM was appointed to the position of Company Secretary and General Counsel effective from 9 August 2019. Ms Jalleh brings more than 19 years’ international oil and gas experience in senior corporate, commercial and legal roles. Her experience spans conventional and unconventional projects, asset and portfolio management, and international M&A transactions. Prior to joining Cooper Energy, Ms Jalleh held the position of Director, Business Development Asia-Pacific for Repsol, based in Singapore. Ms Jalleh has worked in Australia, the Middle East, North America, the UK and South East Asia in roles with Repsol, Talisman Energy, King & Spalding LLP and Santos. Ms Alison Evans B.A., LLB held the position of Company Secretary and Legal Counsel from 25 February 2013 to 9 August 2019. Ms Evans concluded her employment with Cooper Energy on 20 December 2019. 3. Directors’ meetings The number of Directors’ meetings (including meetings of committees of Directors) and number of meetings attended by each of the Directors during the financial year were: Director Board Meetings Mr J. Conde Mr D. Maxwell Mr T. Bednall* Ms V. Binns** Ms E. Donaghey Mr H. Gordon Mr J. Schneider Ms A. Williams A 8 8 2 2 8 8 8 8 B 8 8 2 2 8 8 8 8 A = Number of meetings attended. Audit Committee Meetings Risk & Sustainability Meetings People & Remuneration Committee Meetings Nomination Committee Meetings A - - - 1 3 4 4 4 B - - - 1 3 4 4 4 A - - - - 3 3 - 3 B - - - - 3 3 - 3 A 4 - 1 1 4 - 4 - B 4 - 1 1 4 - 4 - A 1 1 - - 1 1 1 1 B 1 1 - - 1 1 1 1 B = Number of meetings held during the time the Director held office, or was a member of the Committee, during the year (noting that Committee membership was restructured with effect as of 1 May 2020). * Mr Bednall was appointed 31 March 2020. ** Ms Binns was appointed 2 March 2020. 50 Director’s Statutory Report For the year ended 30 June 2020 4. Remuneration Report (audited) Information about the remuneration of the Company’s key management personnel for the financial year ended 30 June 2020 is set out in the Remuneration Report. The information in the Remuneration Report has been audited as required by the Corporations Act 2001 (Cth) and forms part of the Directors’ Report. Introduction to Remuneration Report from the Chairman of the People and Remuneration Committee Dear Shareholder I am pleased to present your Company’s 2020 Remuneration Report for which we will be seeking your support at the 2020 Annual General Meeting. This report is an important element of the Company’s annual reporting. It documents the Company’s remuneration framework and guiding principles, details the remuneration outcomes for its Board and key management personnel, and enables comparison of these remuneration outcomes with the Company’s performance. The People and Remuneration Committee’s view is that this report shows the Company’s remuneration framework to be appropriate, and that the 2020 remuneration outcomes are fair when compared to peer companies and taking account of the Company’s performance over the last few years. Remuneration Report context: 2020 Financial Year The Company’s performance in the 12 months to 30 June 2020 is reported in the Operating and Financial Review of the Financial Report. This performance and how it compared to the specific targets of the Company Scorecard provide the context of the Remuneration Report. Cooper Energy met or exceeded the targets of its Corporate Scorecard in the categories of HSEC, Growth and People & Enablers. The Company failed to meet target in the areas of Production & Revenue and Project Delivery. The Company’s share price decreased by 31% over the 2020 financial year. Notably however Cooper Energy has outperformed most of the peer company set (but not all) on a 1 year basis and has outperformed all on a 5 year basis. A remuneration framework which attracts, encourages, rewards and retains talent is an important foundation that can enable the company to repeat superior total shareholder return and the share price growth that is essential for your Company’s ongoing development. Remuneration developments The Company’s remuneration framework has been stable for some time. The view of the People and Remuneration Committee is that the Company’s remuneration framework and principles have served the Company well. They are simple and relevant and consistent with the objective to attract and retain high calibre employees and provide incentives to deliver superior performance in line with the Cooper Energy Values. Consequently, there has been little change to the Company’s remuneration structure and no change is proposed for the 2021 financial year. Cognisant of community and investor expectations, particularly in light of the economic impact of the COVID-19 pandemic, there is no change in fees payable to Directors proposed for FY21. I confirm that Directors’ fees remain comparable with relevant peer companies. For the same reasons, and consistent with benchmarking within the hydrocarbon industry, the Fixed Annual Remuneration of our Managing Director and Executive Leadership Team will not increase in FY21. Remuneration outcomes The remuneration outcomes detailed in this report are consistent with and recognise the performance of the Company over both the short and long terms. In response to feedback, we have included full year STIP awards paid for FY20. Important components of the Corporate Scorecard that relate to Production and Revenue and also those relating to Growth Projects have been significantly impacted by the late start-up of the onshore gas plant at Orbost. As a consequence, the Board has assessed the Corporate Scorecard result as being 39/100. This past year has presented many challenges for our shareholders, our staff and the many consultants that support us, and of course for their families. The COVID-19 pandemic has also tested how we all work together. Cooper Energy has continued to work in a very focused yet collaborative manner throughout. We thank the Managing Director, the Executive Leadership Team and their teams for their very considerable commitment and contribution over the year. Yours sincerely Mr Jeffrey Schneider Chairman of the People and Remuneration Committee 51 Director’s Statutory Report For the year ended 30 June 2020 4. Remuneration Report continued Contents 4.1 Introduction 4.2 Key Management Personnel covered in this Report 4.3 Remuneration Governance 4.4 Nature & Structure of Executive KMP Remuneration 4.5 Cooper Energy’s Five-Year Performance and Link to Remuneration 4.6 2020 Executive KMP Performance and Remuneration Outcomes 4.7 Executive KMP Employment Contracts 4.8 2020 Remuneration Outcomes for Executive KMP 4.9 Nature of Non-Executive Director Remuneration Page 52 52 53 54 60 61 63 64 68 4.1 Introduction This Remuneration Report (Report) details the approach to remuneration frameworks, outcomes and performance for Cooper Energy. The Remuneration Report forms part of the Directors’ Report and provides shareholders with an understanding of the remuneration principles and practices in place for Key Management Personnel (KMP) for the reporting period. The Report has been prepared in accordance with section 300A of the Corporations Act 2001 and unless specified otherwise, has been audited in accordance with the provisions of section 308(3C) of the Corporations Act 2001. 4.2 Key Management Personnel covered in this Report In this Report, KMP are the people who have the authority and responsibility for planning, directing and controlling the activities of the Group, either directly or indirectly. They are: • the Non-Executive Directors; • the Managing Director; and • the executives on the Executive Leadership Team. The Managing Director and executives on the Executive Leadership Team are referred to in this Report as “Executive KMP”. The following table sets out the KMP of the Group during the reporting period and the period they were KMP: Non-executive Directors Mr J. Conde AO Ms E. Donaghey Mr H. Gordon Mr J. Schneider Ms A. Williams Ms V. Binns1 Mr T. Bednall1 Position Chairman Non-Executive Director Non-Executive Director Non-Executive Director Non-Executive Director Period KMP 1 July 2019 to 30 June 2020 1 July 2019 to 30 June 2020 1 July 2019 to 30 June 2020 1 July 2019 to 30 June 2020 1 July 2019 to 30 June 2020 Non-Executive Director (casual vacancy) 2 March 2020 to 30 June 2020 Non-Executive Director (casual vacancy) 31 March 2020 to 30 June 2020 1. Ms Binns and Mr Bednall were each appointed to a casual vacancy as a Non-Executive Director on the respective dates above. Their appointments are to be confirmed by shareholders at the 2020 Annual General Meeting scheduled for 12 November 2020. Executive KMP Mr D. Maxwell Mr A. Thomas Ms V. Suttell Ms A. Jalleh¹ Mr I. MacDougall Mr E. Glavas Mr M. Jacobsen Position Managing Director Period KMP 1 July 2019 to 30 June 2020 General Manager Exploration & Subsurface 1 July 2019 to 30 June 2020 Chief Financial Officer 1 July 2019 to 30 June 2020 Company Secretary and General Counsel 9 August 2019 to 30 June 2020 General Manager HSEC & Technical Services 1 July 2019 to 30 June 2020 General Manager Commercial & Development 1 July 2019 to 30 June 2020 General Manager Projects & Operations 1 July 2019 to 30 June 2020 1. Ms Jalleh was appointed to the role of Company Secretary and General Counsel on 9 August 2019. 52 Director’s Statutory Report For the year ended 30 June 2020 4. Remuneration Report continued 4.2 Key Management Personnel covered in this Report continued Former Executive KMP Position Period KMP Ms A. Evans1 Mr D. Clegg2 Company Secretary and Legal Counsel 1 July 2019 to 9 August 2019 General Manager Development 1 July 2019 to 31 December 2019 1. Ms Evans ceased being Company Secretary and General Counsel on 9 August 2019. Ms Evans concluded her employment with Cooper Energy on 20 December 2019. 2. Mr Clegg ceased being a member of the Executive Leadership Team on 31 December 2019 (he now has a part-time role with the Company). 4.3 Remuneration Governance 4.3.1 Philosophy and objectives The Company is committed to a remuneration philosophy that aligns to its business strategy and encourages superior performance and shareholder returns. Cooper Energy’s approach towards remuneration aims to ensure that an appropriate balance is achieved among: • maximising sustainable growth in shareholder returns; • operational and strategic requirements; and • providing attractive and appropriate remuneration packages. The primary objectives of the Company’s remuneration policy are to: • attract and retain high-calibre employees; • ensure that remuneration is fair and competitive with both peers and competitor employers; • provide significant incentive to deliver superior performance (when compared to peers) against Cooper Energy’s strategy and key business goals without rewarding conduct that is contrary to the Cooper Energy Values or risk appetite; • achieve the most effective returns (employee productivity) for total employee spend; and • ensure remuneration transparency and credibility for all employees and in particular for Executive KMP, with a view to enhancing Cooper Energy’s reputation and standing in the community. Cooper Energy’s policy is to pay Fixed Annual Remuneration at the median level compared to hydrocarbon industry benchmark data and supplement this with “at risk” remuneration to bring total remuneration within the upper quartile when outstanding performance is achieved. 4.3.2 People and Remuneration Committee The People and Remuneration Committee (which is comprised of 5 Non-Executive Directors, all of whom are independent) makes recommendations to the Board about remuneration strategies and policies for the Executive KMP and considers programs related to executive development and talent management. On an annual basis, the People and Remuneration Committee makes recommendations to the Board about the form of payment and incentives to Executive KMP and the amount. This is done with reference to Company performance and individual performance of the Executive KMP, relevant employment market conditions, current industry practices and independent remuneration benchmark reports. 4.3.3 External remuneration advisers The Committee may consider advice from external advisors who are engaged by and report directly to the Committee. Such advice will typically cover Non-Executive Director fees, Executive KMP remuneration and advice in relation to equity plans. The Corporations Act 2001 requires companies to disclose specific details regarding the use of remuneration consultants. The mandatory disclosure requirements only apply to those advisors who provide a “remuneration recommendation” as defined in the Corporations Act 2001. The Committee did not receive any remuneration recommendations during the reporting period and all remuneration benchmarking was performed in-house against independent Australian hydrocarbon industry remuneration data. 53 Director’s Statutory Report For the year ended 30 June 2020 4. Remuneration Report continued 4.4 Nature & Structure of Executive KMP Remuneration Executive KMP remuneration during the reporting period consisted of a mix of: • Fixed Annual Remuneration (FAR); • Short Term Incentive Plan (STIP) participation; • benefits such as accommodation, internet allowance and car parking; and • Long Term Incentive Plan (LTIP) (composed of performance rights (PRs) and share appreciation rights (SARs) under the Company’s amended Equity Incentive Plan approved by shareholders at the 2019 AGM). It is the Company’s policy that the performance-based (or at risk) pay forms a significant portion of the Executive KMPs’ total remuneration. The Company aims to achieve an appropriate balance between rewarding operational performance (through the STIP cash reward) and rewarding long-term sustainable performance (through the LTIP). The Company’s remuneration profile for Executive KMP is as follows: Managing Director Remuneration Mix at Maximum Performance (Super Stretch) Other Executive KMP Remuneration Mix at Maximum Performance (Super Stretch) 33.33% 33.33% 31.8% 45.5% 33.33% 22.7% Fixed Annual Remuneration (FAR) Short Term Incentive Plan (STIP) Long Term Incentive Plan (LTIP) 4.4.1 Remuneration strategy and framework - Linking Reward to Performance The remuneration strategy sets the direction for the remuneration framework and drives the design and application of remuneration for the Company, including Executive KMP. The remuneration strategy: • encourages a strong focus on financial and operational performance, and motivates Executive KMP to deliver sustainable business results and returns to the Company’s shareholders over the short and long term; • attracts, motivates and retains appropriately qualified and experienced talent; and • aligns executive and shareholder interests through equity linked plans. The Board believes that remuneration should include a fixed component and at-risk or performance-related components, including both short term and long-term incentives. This remuneration framework is shown in the table following, including how performance outcomes will impact remuneration outcomes for Executive KMP. The Board will continue to review the remuneration framework to ensure it continues to align with the Company’s strategic objectives. No significant changes to the key elements of the remuneration framework are anticipated in FY21. 54 Director’s Statutory Report For the year ended 30 June 2020 4. Remuneration Report continued 4.4 Nature & Structure of Executive KMP Remuneration continued 4.4.2 Remuneration strategy and framework – Overview Fixed Annual Remuneration Salary and other benefits (including statutory superannuation) Short Term Incentive Plan (STIP) Annual incentive opportunity delivered in cash based on Company and individual performance Performance Conditions Key Considerations • Scope of individual’s role • Individual’s level of knowledge, skills and expertise • Individual performance • Market benchmarking Strategy & Project Key Performance Indicators (KPIs) (up to 40% of Company performance related STIP award) • Major Projects & Development • Growth in Reserves & Resources • Key Gas Strategy Milestones • Acquisition and Divestment Operational & Financial KPIs (up to 40% of Company performance related STIP award) • Production and Revenue • Cost Management • Process & Risk Management • People and Stakeholder relationships Safety & Sustainability KPIs (up to 20% of Company performance related STIP award) • Lead improvement objectives for environmental and fatality prevention • Sustainability and community relationships • Total Recordable Case Frequency Rate (TRCFR) target Individual performance KPIs (up to 25% for Managing Director & 30% for the other Executive KMP of Final STIP award) aligned to strategic objectives. Remuneration Strategy/Performance Link Fixed Annual Remuneration is set to attract, retain and motivate the right talent to deliver on the strategy and contribute to the Company’s financial and operational performance. For executives new to their role, the aim is to set Fixed Annual Remuneration at relatively modest levels compared to their peers and to progressively increase as they gain experience and perform at higher levels. This links fixed remuneration to individual performance. STIP performance conditions are designed to support the financial and strategic direction of the Company (the achievement links to shareholder returns) and are clearly defined and measurable. A large proportion of outcomes are subject to the Operational & Financial targets of the Company or business unit, depending on the role of the executive to ensure line of sight. Strategy & Project targets ensure that continued focus on future opportunities is maintained. Non-financial targets are aligned to core Values (including safety and sustainability) and key strategic and growth objectives. Threshold, Target, Stretch and Super Stretch targets for each measure are set by the Board to ensure that a challenging performance-based incentive is provided. The Board has discretion to adjust STIP outcomes up or down to ensure appropriate individual outcomes and results align with the Company’s Values. Individual performance measures are agreed each year. The individual measures relate to business unit objectives, promotion of Company Values and identified areas for development. This ensures a clear focus on “how we work” i.e. our Values and culture, as well as what we seek to achieve. 55 Director’s Statutory Report For the year ended 30 June 2020 4. Remuneration Report continued 4.4 Nature & Structure of Executive KMP Remuneration continued 4.4.2 Remuneration strategy and framework – Overview continued Long Term Incentive Plan (LTIP) Three-year incentive opportunity delivered through Performance Rights (PRs) and Share Appreciation Rights (SARs) Performance Conditions Remuneration Strategy/Performance Link LTIP is a mix of PRs and SARs. Maximum LTIP grant is 100% of Fixed Annual Remuneration for Managing Director and 70% of Fixed Annual Remuneration for other Executive KMP. Relative Total Shareholder Return is the only performance condition. Relative Total Shareholder Return ensures that LTIP can only vest when the Company’s share price performance is at least at the 50th percentile of the peer group. Maximum LTIP vesting can only occur at or above 90th percentile of the peer group. • Relative Total Shareholder Return performance is where there is sustained superior share price performance of the Company compared to a Peer Group of companies. • Peer Group Companies are 12 ASX-listed companies in the oil and gas sector, with a range of market capitalisation. • SARs by their nature have an absolute total shareholder return requirement. No SAR will vest unless the share price appreciates over the measurement period. Allocation of PRs & SARs upfront encourages executives to ‘behave like shareholders’ from the grant date. The PRs & SARs are restricted and subject to risk of forfeiture at the end of the three-year performance period. The Company believes that encouraging its employees to become shareholders is the best way of aligning employee interests with those of the Company’s shareholders. The LTIP also acts as a retention incentive for key talent (due to the three-year vesting period). Relative Total Shareholder Return is designed to encourage executives to focus on the key performance drivers which underpin sustainable growth in shareholder value. The Relative Total Shareholder Return performance condition is designed to ensure vesting can only occur where shareholders have enjoyed superior share price performance compared to the peer group shareholders. SARs only have value when there is an increase in the Company’s share price. In general, the Company’s vesting hurdles are intended to be tougher than our industry peers. Total Remuneration: The combination of these elements is designed to attract, retain and motivate appropriately qualified and experienced individuals, encourage a strong focus on performance, support the delivery of outstanding returns to shareholders and align executive and stakeholder interests through share ownership. 4.4.3 Fixed Annual Remuneration Fixed Annual Remuneration includes base salary (paid in cash) and statutory superannuation. Executives are paid Fixed Annual Remuneration which is competitive in the markets in which the Company operates and is consistent with the responsibilities, accountabilities and complexities of the respective roles. The Company benchmarks Executive KMP Fixed Annual Remuneration against hydrocarbon industry market surveys which are published annually. Additionally, the pay levels of Executive KMP positions in the Company may be benchmarked against national market executive remuneration surveys. It is the Company’s policy to position itself at the median level of the market when benchmarking Fixed Annual Remuneration. 4.4.4 Short Term Incentive Plan (STIP) - Overview The STIP is an annual incentive opportunity delivered in cash based on a mix of Company and individual performance. The individual measures are a mixture of business unit and employee-specific goals. The Company performance measures in the Company’s scorecard and weightings are as follows: Performance Measures HSEC (20%) • Health Rationale Targeting: • Safety (Lost Time Injury, Total Recordable • Leading HSEC performance Incident Frequency Rate) • Environment (reportable environmental incidents) • Community (strategy, grievance management) • HSEC Management System • Efficient processes (cost & time), easily understood • Cooper Energy team clearly engaged & continually improving • Leading emissions management 56 Director’s Statutory Report For the year ended 30 June 2020 4. Remuneration Report continued 4.4 Nature & Structure of Executive KMP Remuneration continued 4.4.4 Short Term Incentive Plan (STIP) - Overview continued Performance Measures Rationale Production & Revenue (20%) • Production MMboe • Revenue A$ million Targeting growing value by increasing production & margin from existing permits • Gas marketing $/GJ average spot and new sales prices • Cash margin A$/boe (sales revenue less cash operating costs (excludes DD&A) Project Delivery (20%) • Schedule • Cost Targeting: • Major capital projects delivered per scope, within schedule and • Front End Engineering & Design and Final budget, with appropriate contingency included Investment Decisions • Clear management systems • Consistent successful major project delivery Growth (20%) • Reserves Targeting: • Gas marketing • Acquisitions & divestments • Development projects per schedule and adding economic value • Term gas contracts that underpin new business and add value (in each case to reflect a growing business) • Maximising value through portfolio management and acquisitions and divestment • Leveraging competitive strengths • Building growth Targeting: • “One team” performance • Applying the Cooper Energy Values and culture to deliver our strategy • Tight cost management, accurate forecasting • Funding fit for purpose, creating shareholder value and being optimised • Efficient, cost-effective management and IT systems helping to make jobs easier. • Stakeholder relationships creating value People, Culture & Enablers (20%) • Cost Management • Funding • Processes and Risk Management • People • Stakeholder Relationships Please note as follows: “HSEC” means Health Safety Environment & Community “MMboe” means Million barrels of oil equivalent “GJ” means Gigajoule “DD&A” means Depreciation, Depletion & Amortisation 57 Director’s Statutory Report For the year ended 30 June 2020 4. Remuneration Report continued 4.4 Nature & Structure of Executive KMP Remuneration continued 4.4.4 Short Term Incentive Plan (STIP) - Overview continued The key features of the STIP for the FY2020 are as follows: STIP FY20 Plan Feature Details What is the purpose of the STIP? The STIP is designed to motivate and reward Executive KMP for their contribution to the annual performance of the Company. How does the STIP align with the interests of Cooper Energy’s shareholders? The STIP is aligned to shareholder interests by encouraging Executive KMP to achieve operational and business milestones in a balanced and sustainable manner. What is the vehicle of the STIP award? The STIP award is delivered in the form of a cash payment, usually in October. What is the maximum award opportunity (% of Fixed Remuneration)? Managing Director Other Executive KMP 100% 50% What is the performance period? How are the performance measures determined and what are their relative weightings? Each year, the Board reviews and approves the performance criteria for the year ahead by approving a Company scorecard and individual performance contracts are agreed with each Executive KMP. The Company’s STIP operates over a 12-month performance period from 1 July to 30 June. The measurement of Company performance is based on the achievement of key performance indicators (KPIs) set out in a Company scorecard. See section 4.6.2 for the Company scorecard measures used for FY20. The KPIs focus on the core elements the Board believes are needed to successfully deliver the Company strategy and maximise sustainable shareholder returns. For each KPI in the scorecard, a base or threshold performance level is established as well as a target, stretch and super stretch (i.e. maximum). Personal performance measures are agreed between each Executive KMP and Cooper Energy each year. These relate to the individual’s performance in achieving things such as business unit objectives, promotion of the Cooper Energy Values and identified areas for development. The relative weighting of Company scorecard and individual performance is as follows: • Managing Director – 75% Company: 25% individual • Executives – 70% Company: 30% individual Performance measures are challenging and maximum award opportunities are only achieved by outstanding performance. 50% of the maximum award opportunity will be awarded if the Company meets target level performance. Target level KPIs are set at a challenging and achievable level of performance (and not at the base level of performance). 0% STIP will be awarded for base level achievement. 0% STIP will be awarded if during any measurement period the Company sustains a fatality or major environmental incident. Irrespective of the scorecard outcome, payment of any STIP is entirely at the discretion of the Board. 58 Director’s Statutory Report For the year ended 30 June 2020 4. Remuneration Report continued 4.4 Nature & Structure of Executive KMP Remuneration continued 4.4.5 Long Term Incentive Plan (LTIP) - Overview In the reporting period, the LTIP involved grants of Performance Rights (PRs) and Share Appreciation Rights (SARs) under the Equity Incentive Plan. The key features of the grants made in the 2020 financial year (granted December 2019) are set out in the following table: FY20 LTIP Plan Feature Details What is the purpose of the LTIP? The Company believes that encouraging its employees, including Executive KMP, to become shareholders is the best way of aligning their interests with those of the Company’s shareholders. Having a LTIP is also intended to be a retention incentive for employees (with a vesting period of at least three years before securities under the plan are available to employees). How is the LTIP aligned to shareholder interests? Employees only benefit from the LTIP when there is sustained superior share price performance of the Company compared to relevant peer group companies. This aligns the LTIP with the interests of shareholders. What is the vehicle of the LTIP? During the reporting period, the LTIP involved grants of 50% PRs and 50% SARs. A PR is a right to acquire one fully paid share in the Company provided a specified hurdle is met. SARs are rights to acquire shares in the Company to the value of the difference in the Company share price between the grant date and vesting date. What is the maximum annual LTIP grant (% of Fixed Remuneration)? Managing Director Executive KMP Senior staff 100% 70% 50% What is the LTIP performance period? The performance period is three years. What are the performance measures? Grants in years prior to the 2019 financial year allowed for re-testing 12 months following the end of the performance period. A re-test was considered appropriate because the Company’s growth has been dependent on development of projects that have generally taken greater than three years from conception to start-up. Given the growth of the Company, including its development activities, the Company will no longer be reliant on single projects, such as the Sole development. As a consequence, the Board determined that re-testing would not form part of the terms of the Incentives for future grants. Re-testing is not a feature of the Equity Incentive Plan approved by shareholders at the 2019 Annual General Meeting. 100% of the grant (both PRs and SARs) is subject to a Relative Total Shareholder Return performance measure. Relative Total Shareholder Return is a common long-term incentive measure across ASX-listed companies and is aligned with shareholder returns. Relative measures ensure that maximum incentives are only achieved if Cooper Energy’s performance exceeds that of its peers and therefore supports competitive returns against other comparable organisations. In addition to the Relative Total Shareholder Return performance measure set by the Board, SARs by their nature also have a natural absolute total shareholder return measure. No SARs will be exercisable unless the share price appreciates over the measurement period. What is the vesting schedule? The level of vesting will be determined based on the ranking against the comparator group of companies in accordance with the following schedule: • below the 50th percentile no rights vest; • at the 50th percentile 30% of the rights vest; • between the 50th percentile and 90th percentile pro rata vesting; and • at the 90th percentile or above, 100% of the rights will vest. The vesting schedule reflects the Board’s requirement that performance measures are challenging, and maximum award opportunities are only achieved by outstanding performance. 59 Director’s Statutory Report For the year ended 30 June 2020 4. Remuneration Report continued 4.4 Nature & Structure of Executive KMP Remuneration continued 4.4.5 Long Term Incentive Plan (LTIP) - Overview continued FY20 LTIP Plan Feature Details Which companies make up the Relative TSR peer group? What happens on cessation of employment? The Relative Total Shareholder Return of the Company is measured as a percentile ranking compared to the following comparator Group of 12 listed entities: Woodside Petroleum Limited; Oil Search Limited; Santos Limited; Beach Energy Limited; Senex Energy Limited; Karoon Gas Australia Limited; FAR Limited; Central Petroleum Limited; Buru Energy Limited; Carnarvon Petroleum Limited; Strike Energy Limited; Horizon Oil Limited. The peer group was based on a group of ASX-listed companies in the oil and gas sector, with a range of market capitalisation. Generally, if an employee ceases employment prior to the vesting date (e.g. to take a position with another company), they will forfeit all awards. In the case of “qualifying leavers” as defined (examples of which include redundancy, retirement or incapacity) awards may be retained unless the Board determines otherwise. The Board also has a discretion to determine that some or all awards may be retained upon cessation of employment. What happens if there is a change of control? In the event of a change of control, unless the Board determines otherwise, pro-rata vesting will occur on the basis of the proportion of the relevant performance period that has elapsed. Who can participate in the LTIP? Eligibility is generally restricted to Executive KMP and other senior staff who are in a position to influence shareholder value the most. Is there a cap on dilution? 5% total on issue (excluding KMP). Will the Company make any changes to the LTIP for the grant to be made in the 2021 financial year? It is not anticipated that the general structure of the LTIP will change for grants made in FY21. However, the Board will continue to review the appropriateness of the performance measures as the Company transitions from development to gas production and sale. 4.5 Cooper Energy’s Five-Year Performance and Link to Remuneration The following graphs illustrated the five-year performance and links to the remuneration strategy and framework: Annual Production (MMboe) Proved & Probable Reserves (MMboe) 1.49 1.31 1.50 0.96 0.46 3.0 11.7 52.4 52.7 49.9 FY16 FY17 FY18 FY19 FY20 FY16 FY17 FY18 FY19 FY20 Links directly to Company STIP reward outcomes as an Operational & Financial KPI. Links directly to Company STIP reward outcome as a Growth KPI. Total Recordable Incident Frequency Rate (events per hours worked) Sales Revenue ($ million) 4.07 3.53 1.98 27.4 39.1 67.5 75.5 78.1 0.0 FY16 FY17 FY18 0.0 FY19 FY20 FY16 FY17 FY18 FY19 FY20 Links directly to Company STIP reward outcome as a Safety & Sustainability KPI. Links directly to Company STIP reward outcome as an Operational & Financial KPI. 60 Financial – Profit After Tax ($ million) Financial – Earnings Per share (cents) 27.0 -12.3 -12.1 -34.8 -10.1 1.8 -1.8 -0.7 -5.3 FY16 FY17 FY18 FY19 FY16 FY17 FY18 FY19 FY20 Links directly to Company STIP reward outcome as an Operational Links directly to Company LTIP reward outcome by increasing & Financial KPI through cost management. shareholder value. Financial – Total Shareholder Return (%) Capital As At 30 June Share Price ($ per share) 72.7 40.3 6.0 0.38 0.39 0.375 0.54 0.22 -12.2 FY16 FY17 FY18 FY19 FY16 FY17 FY18 FY19 FY20 Links directly to Company LTIP reward outcome by increasing Links directly to Company LTIP reward outcome by increasing shareholder value. shareholder value compared to peers. -86.0 FY20 -30.6 FY20 Capital As At 30 June – Market Capitalisation ($ million) 875.6 616.4 610.0 433.4 93.6 FY16 FY17 FY18 FY19 FY20 Links directly to Company LTI reward outcome by increasing shareholder value compared to peers. Annual Production (MMboe) Proved & Probable Reserves (MMboe) 1.49 1.31 1.50 0.96 0.46 3.0 11.7 52.4 52.7 49.9 FY16 FY17 FY18 FY19 FY20 FY16 FY17 FY18 FY19 FY20 Links directly to Company STIP reward outcomes as an Links directly to Company STIP reward outcome as a Growth KPI. Operational & Financial KPI. Total Recordable Incident Frequency Rate (events per hours worked) Director’s Statutory Report For the year ended 30 June 2020 4.07 3.53 1.98 Sales Revenue ($ million) 67.5 75.5 78.1 27.4 39.1 0.0 FY16 FY17 FY18 0.0 FY19 FY20 FY16 FY17 FY18 FY19 FY20 4. Remuneration Report continued Links directly to Company STIP reward outcome as a Safety & Sustainability KPI. Links directly to Company STIP reward outcome as an Operational & Financial KPI. 4.5 Cooper Energy’s Five-Year Performance and Link to Remuneration continued Financial – Profit After Tax ($ million) Financial – Earnings Per share (cents) 27.0 -12.3 -12.1 -34.8 FY16 FY17 FY18 FY19 -86.0 FY20 -10.1 1.8 -1.8 -0.7 -5.3 FY16 FY17 FY18 FY19 FY20 Links directly to Company STIP reward outcome as an Operational & Financial KPI through cost management. Links directly to Company LTIP reward outcome by increasing shareholder value. Financial – Total Shareholder Return (%) Capital As At 30 June Share Price ($ per share) 72.7 40.3 6.0 -12.2 FY16 FY17 FY18 FY19 -30.6 FY20 0.38 0.39 0.375 0.54 0.22 FY16 FY17 FY18 FY19 FY20 Links directly to Company LTIP reward outcome by increasing shareholder value. Links directly to Company LTIP reward outcome by increasing shareholder value compared to peers. Capital As At 30 June – Market Capitalisation ($ million) 875.6 616.4 610.0 433.4 93.6 FY16 FY17 FY18 FY19 FY20 Links directly to Company LTI reward outcome by increasing shareholder value compared to peers. In FY20 and in the past 5 years dividends were not paid by the Company to its shareholders, nor was there a return of capital by the Company to its shareholders. However, Cooper Energy recorded a superior total shareholder return when compared to the large majority of its peers in both the short and long-term assessment periods. While the Company’s share price decreased by 31% over the 2020 financial year, it has increased 1.8 times (share price increase of 83%) in the 5 years to 30 June 2020. Cooper Energy has outperformed most of its peer set on a 1 year basis and all on a 5 year basis. 4.6 2020 Executive KMP Performance and Remuneration Outcomes 4.6.1 Fixed Annual Remuneration outcome The Fixed Annual Remuneration for the Managing Director and other Executive KMP were reviewed at the end of the FY20 financial year. No increases to Fixed Annual Remuneration were awarded as a result of this review. During FY20 Executive KMP Fixed Annual Remuneration increases were in the range of 2.86% - 7.59%, reflecting industry benchmarking and in line with the Company’s remuneration strategy. The scope of the roles of some Executive KMP also materially increased in FY20. 4.6.2 STIP performance outcomes – Company Results The Company Scorecard results for the reporting period ranged between Threshold and Stretch and cover the full FY20. The Company’s FY20 result was a score of 39 out of 100. 61 Director’s Statutory Report For the year ended 30 June 2020 4. Remuneration Report continued 4.6 2020 Executive KMP Performance and Remuneration Outcomes continued 4.6.2 STIP performance outcomes – Company Results continued Company Scorecard Results FY20 Performance Measure (Weighting %) HSEC (20%) Production & Revenue (20%) Project Delivery (20%) Growth (20%) People, Culture & Enablers (20%) FY20 Performance: Threshold Target Stretch Super Stretch Performance Measure Outcome TRIFR 3.39. No reportable environmental incidents. Community relationships enhanced. COVID-19 managed well.Assessed Score: 12/20 Production of 1.52 MMboe Assessed Score: 0/20 Sole offshore within schedule and budget. Delays at Orbost Gas Processing Plant. Athena Gas Plant FID. Assessed Score: 2/20 Annie success. Successful GSA management. No material acquisition or divestments. Assessed Score: 10/20 Cost management effective. Continuous improvement of risk management, processes and management systems. Ongoing high level of stakeholder engagement. Assessed Score: 15/20 4.6.3 STIP performance outcomes – Individual Results Short Term Incentive (STI) for the year ended 30 June 2020 STI target % of Fixed Annual Remuneration STI maximum % of Fixed Annual Remuneration Cash STI $ % earned of maximum STI opportunity % forfeited of maximum STI opportunity Executive KMP Mr D. Maxwell Mr A. Thomas Ms V. Suttell Ms A. Jalleh¹ Mr I. MacDougall Mr E. Glavas Mr M. Jacobsen Former Executive KMP Mr D. Clegg² 50% 25% 25% 25% 25% 25% 25% 25% 100% 50% 50% 50% 50% 50% 50% 439,200 108,570 110,880 87,210 98,325 98,175 102,293 48.00% 46.20% 46.20% 46.20% 42.75% 46.20% 44.48% 52.00% 53.80% 53.80% 53.80% 57.25% 53.80% 55.52% 50% 43,009 42.75% 57.25% 1. Ms Jalleh commenced as an Executive KMP on 9 August 2019. 2. Mr Clegg ceased as a member of the Executive Leadership Team on 31 December 2019. 62 Director’s Statutory Report For the year ended 30 June 2020 4. Remuneration Report continued 4.6 2020 Executive KMP Performance and Remuneration Outcomes continued 4.6.4 LTIP Outcome The Company’s Relative Total Shareholder Return compared to the peer group is set out below for the LTIP grant that vested in December 2019. The base for the graph is December 2016, being the grant date of PRs and SARs that were made under the Company’s Equity Incentive Plan. The terms of the Equity Incentive Plan are set out in section 4.4.5. Share Price Performance of Cooper Energy Limited Versus the Then Applicable Peer Group – 8 December 2016 to 7 December 2019 -150% -100% -50% 0% 50% 100% 150% 200% 250% Cooper Energy Limited 83% 35% 148% 73% 3% 41% -8% 208% 213% 230% -59% -100% The value of LTI that vested in December 2019 decreased compared to December 2018. The award which vested during the 2020 financial year contained fewer rights than the previous award which vested in December 2018. The vesting of this award was also impacted by the performance of the Company’s share price against its peers over the measurement period. Over the three-year measurement period from 8 December 2016 to 8 December 2019, Cooper Energy’s total shareholder return was 83% and it achieved a Relative Total Shareholder Return percentile rank of 60%. This resulted in a vesting outcome of 47% of all performance rights and SARs that were granted in December 2016. 4.7 Executive KMP Employment Contracts Each KMP has an ongoing employment contract. All KMP have termination benefits that are within the allowed limit in the Corporations Act 2001 without shareholder approval. Contracts include the treatment of entitlements on termination in the event of resignation, with notice or for cause. Key terms for each Executive KMP are set out below: Executive KMP Notice by Cooper Energy Notice by Executive KMP Indemnity Agreement Treatment on Termination by Cooper Energy David Maxwell 12 months 6 months Other Executive KMP 6 months 3 months Company provides Indemnity Agreement, Directors and Officers indemnity insurance and access to Company records. Where the Managing Director is not employed for the full period of notice a payment in lieu may be made. A payment in lieu of notice is based on Fixed Remuneration (base salary and superannuation). Upon termination, superannuation is not paid on accrued annual leave or long service leave. Unused personal leave is not paid out and is forfeited. Company provides Indemnity Agreement, Directors and Officers indemnity insurance and access to Company records. Where an Executive KMP is not employed for the full period of notice a payment in lieu may be made. A payment in lieu of notice is based on Fixed Remuneration (base salary and superannuation). Upon termination, superannuation is not paid on accrued annual leave or long service leave. Unused personal leave is not paid out and is forfeited. 63 Director’s Statutory Report For the year ended 30 June 2020 4. Remuneration Report continued 4.8 2020 Remuneration Outcomes for Executive KMP 4.8.1 Remuneration realised by Executive KMP in 2020 and 2019 (not audited) The Company believes that reporting remuneration realised by Executive KMP is useful to shareholders and provides clear and transparent disclosure of remuneration provided by the Company. The tables set out below show amounts paid to Executive KMP and the cash value of equity awards which vested during the reporting period. This information is non-IFRS and is in addition to and different from the disclosures required by the Corporations Act 2001 and Accounting Standards in the rest of the Remuneration Report and the tables in sections 4.8.2 and 4.9.3. The information in this section 4.8.1 is not audited. The total benefits actually delivered during the reporting period and set out in the table below comprise the following elements: • Fixed Annual Remuneration is base salary and superannuation (statutory and salary sacrifice); • STIP cash payment made in October each year. This is the STIP awarded for performance over the 2018 and 2019 performance period i.e. the STIP paid in 2020 related to performance over the 2019 financial year and the STIP paid in 2019 related to performance over the 2018 financial year; • LTIP realised based on the market value of PRs and SARs that vested in December 2018 & 2019 (granted in December 2015 & 2016 respectively); and • “Other” is the value of benefits including fringe benefits tax on accommodation, car parking and other benefits. Executive KMP Year Fixed Remuneration1 $ Mr D. Maxwell Mr A. Thomas Ms V. Suttell Ms A. Jalleh² Mr I. MacDougall Mr E. Glavas Mr M. Jacobsen Former Executive KMP Ms A. Evans3 Mr D. Clegg4 2020 2019 2020 2019 2020 2019 2020 2020 2019 2020 2019 2020 2019 2020 2019 2020 2019 905,247 845,000 463,250 437,250 472,500 435,520 347,532 453,750 415,933 417,500 390,000 453,750 401,342 117,370 351,000 257,045 524,018 STIP1 $ 614,363 646,000 148,793 152,880 161,743 166,306 - 131,075 145,635 132,671 141,703 121,721 164,535 114,471 127,533 155,587 182,000 LTIP1 $ 801,800 2,476,215 286,646 885,256 - - - 274,891 848,953 204,299 630,939 - - 144,100 425,971 - - Other $ 74,755 80,904 6,515 5,916 6,515 5,916 35,535 6,515 5,916 6,515 5916 536 536 4,384 5,916 268 536 Total $ 2,396,165 4,048,119 905,204 1,481,302 640,758 607,742 383,067 866,231 1,416,437 760,985 1,168,558 576,007 566,413 380,325 910,420 412,900 706,554 1. Amounts above include adjustments for unpaid leave where applicable. Disclosure of realised LTIP in 2019 was the accounting fair value of rights that vested during the period. Comparatives have been revised to reflect the market value of the vested shares at the time of issue. 2. Ms Jalleh commenced as an Executive KMP on 9 August 2019 and her entitlements are prorated. 3. Ms Evans worked part time and ceased as an Executive KMP on 9 August 2019 (0.9 full time equivalent to 28 June 2019, and 0.4 full time equivalent to 20 December 2019). Her FY20 entitlements are prorated. 4. Mr Clegg ceased to be a member of the Executive Leadership Team and as an Executive KMP on 31 December 2019. 64 Director’s Statutory Report For the year ended 30 June 2020 4. Remuneration Report continued 4.8 2020 Remuneration Outcomes for Executive KMP continued 4.8.2 Table of Executive KMP Statutory Remuneration Disclosure for 2020 and 2019 financial years Short-term Base Salary STIP (a) Benefits Other Short-term Benefits(b) Long- term Long Service Leave Post Employment(c) Share Based Remuneration(e) Superannuation(d) LTIP Total Executive KMP Mr D. Maxwell Mr A. Thomas Ms V. Suttell Ms A. Jalleh(f) Mr I. MacDougall $ $ $ $ 2020 884,245 510,298 74,755 17,601 2019 2020 2019 2020 2019 2020 2020 2019 824,469 622,946 80,904 34,796 442,247 123,270 6,515 16,993 416,719 145,374 5,916 16,358 451,497 136,412 6,515 35,691 414,989 164,023 5,916 328,279 87,210 35,535 - - 432,747 97,729 6,515 10,572 395,402 135,829 5,916 14,303 Mr E. Glavas 2020 396,497 111,282 6,515 5,257 2019 369,469 134,847 5,916 13,548 Mr M. Jacobsen 2020 432,747 92,343 2019 380,811 154,729 536 536 17,017 13,730 Former Executive KMP Ms A. Evans(g) 2020 2019 107,923 6,864 4,384 (55,618) 330,469 121,362 5,916 12,472 Mr D. Clegg(h) 2020 246,544 39,682 2019 503,487 172,380 268 536 - - $ 21,003 20,531 21,003 20,531 21,003 20,531 19,252 21,003 20,531 21,003 20,531 21,003 20,531 9,446 20,531 10,501 20,531 $ $ 762,633 2,270,535 739,175 2,322,821 258,707 868,735 249,745 854,643 219,540 870,658 133,503 738,962 41,231 511,507 254,572 823,138 244,208 816,189 224,387 764,941 202,241 746,552 216,800 780,446 134,073 704,410 154,624 227,623 166,114 656,864 99,576 396,571 160,349 857,283 a) The STIP values noted for 2020 and 2019 include an under/over accrual representing the delta between the prior period accrual and what was actually paid in respect of that year. This variance will not exist in future periods. Refer to 4.6.3 for STIP amount earnt in FY20 which will be paid in FY21. b) Other short-term benefits include fringe benefits on accommodation, car parking and other benefits. c) Superannuation is the only applicable post-employment benefit ie. No pension or similar benefits for Executive KMP. d) Superannuation includes the amounts required to be contributed by the Company and does not include amounts salary sacrificed. e) In accordance with the requirements of the Accounting Standards, remuneration includes a proportion of the value of the equity-linked compensation determined as at the grant date of the PRs and progressively expensed over the vesting period. The amount allocated as remuneration is not relative to or indicative of the actual benefit (if any) that may ultimately be realised should the equity instruments vest. The value of the PRs was determined in accordance with AASB 2 Share-based Payments and is discussed in Section 4.11 above and in more detail in Note 27 of the Notes to the Financial Statements. f) Ms Jalleh commenced as an Executive KMP on 9 August 2019 and her entitlements are prorated. g) Ms Evans worked part time and ceased as an Executive KMP on 9 August 2019 (0.9 full time equivalent to 28 June 2019, and 0.4 full time equivalent to 20 December 2019). Her FY20 entitlements are prorated. The negative value for long service leave is as a result of the unwinding of the accrual on cessation of employment. h) Mr Clegg ceased to be a member of the Executive Leadership Team and as an Executive KMP on 31 December 2019. 65 Director’s Statutory Report For the year ended 30 June 2020 4. Remuneration Report continued 4.8 2020 Remuneration Outcomes for Executive KMP continued 4.8.3 Performance Rights and Share Appreciation Rights accounting for the reporting period. The value of the PRs and SARs issued under the Equity Incentive Plan is recognised as Share Based Payments in the Company’s statement of comprehensive income and amortised over the vesting period. PRs and SARs were granted under the Equity Incentive Plan on 10 December 2019. The PRs and SARs were granted for no consideration and the employee received no cash benefit at the time of receiving the rights. The cash benefit will be received by the employee following the sale of the resultant shares, which can only be achieved after the rights have been vested and the shares are issued. PRs and SARs granted under the Equity Incentive Plan were valued by an independent consultant who applied the Monte Carlo simulation model to determine the probability of achievement of the Relative Total Shareholder Return against performance conditions. The value of PRs and SARs shown in the tables below are the accounting fair values for grants in the reporting period: Performance Rights (Equity Incentive Plan) Share Appreciation Rights (Equity Incentive Plan) No. of rights granted during period Fair value of rights at grant date No. of rights vested during period % of rights vested to 30 June 2020 No. of rights granted during period Fair value of rights at grant date No. of rights vested during period % of rights vested to 30 June 2020 Directors Mr D. Maxwell 795,652 299,961 637,598 41% 2,779,465 439,155 1,666,575 41% Executive KMP Mr A. Thomas 286,086 107,854 227,943 42% 999,392 157,904 595,807 Ms V. Suttell 292,173 110,149 Ms A. Jalleh¹ 228,260 86,054 - - Mr I. MacDougall 280,000 105,560 218,595 Mr E. Glavas 258,695 97,528 162,460 Mr M. Jacobsen 280,000 105,560 - 0% 0% 42% 38% 0% 1,020,656 161,264 797,387 125,987 - - 978,128 154,544 571,373 903,705 142,785 424,643 978,128 154,544 - Former Executive KMP Ms A. Evans² - - 114,935 38% - - 300,259 Mr D. Clegg³ 328,695 123,918 - 0% 1,148,238 181,422 - 1. Ms Jalleh commenced as an Executive KMP on 9 August 2019. 2. Ms Evans ceased as an Executive KMP on 9 August 2019. 3. Mr Clegg ceased as a member of the Executive Leadership Team and as an Executive KMP on 31 December 2019. 42% 0% 0% 42% 38% 0% 40% 0% The vesting date of the PRs granted on 11 December 2019 is 10 December 2022. The fair value of these rights is $0.38 per right and the share price on grant date was $0.575. The performance period for these PRs commenced on 11 December 2019. The vesting date of the SARs granted on 11 December 2019 is 10 December 2022. The fair value of these rights is $0.158 per right and the share price on grant date was $0.575. The performance period for these SARs commenced on 11 December 2019. 66 Director’s Statutory Report For the year ended 30 June 2020 4. Remuneration Report continued 4.8 2020 Remuneration Outcomes for Executive KMP continued 4.8.4 Movement in Performance Rights (PRs) The movement during the reporting period in the number of PRs granted but not exercisable over ordinary shares in Cooper Energy held, directly, indirectly or beneficially, by each KMP, including their related parties, is as follows: Performance Rights (Equity Incentive Plan) Held at 1 July 2019 Granted Lapsed Vested & Exercised Held at 30 June 2020 Directors Mr D. Maxwell1 Mr H. Gordon2 Executive KMP Mr A. Thomas Ms V. Suttell Ms A. Jalleh³ Mr I. MacDougall Mr E. Glavas Mr M. Jacobsen Former Executive KMP Ms A. Evans⁴ Mr D. Clegg⁵ 3,831,347 365,449 1,289,106 831,739 - 1,264,490 1,069,364 832,131 901,324 996,103 795,652 - 286,086 292,173 228,260 280,000 258,695 280,000 - 328,695 - - - - - - - - - - 637,598 184,766 227,943 - - 218,595 162,460 - 114,935 - 3,989,401 180,683 1,347,249 1,123,912 228,260 1,325,895 1,165,599 1,112,131 786,389 1,324,798 1. As a consequence of the Equity Incentive Plan amendments approved by shareholders at the Company’s Annual General Meeting held on 7 November 2019 (see note below), the terms of the PRs held by Mr Maxwell at 1 July 2019 were also amended. 2. PRs were granted to Mr Gordon when he was an Executive Director. 3. Ms Jalleh commenced as an Executive KMP on 9 August 2019. 4. Ms Evans ceased as an Executive KMP on 9 August 2019. 5. Mr Clegg ceased as a member of the Executive Leadership Team and as an Executive KMP on 31 December 2019. The terms of the PRs held at 1 July 2019 were amended following shareholder approval at the Company’s Annual General Meeting held on 7 November 2019 to provide that “good leavers” would retain rights held upon cessation of employment, subject to a Board discretion to determine otherwise. Rights were also amended to provide for pro-rata vesting of rights upon a change of control event on the basis of the proportion of the relevant performance period that has elapsed. Share Appreciation Rights (Equity Incentive Plan)⁶ Held at 1 July 2019 Granted Lapsed Vested & Exercised⁶ Held at 30 June 2020 Directors Mr D. Maxwell¹ Mr H. Gordon² Executive KMP Mr A. Thomas Ms V. Suttell Ms A. Jalleh³ Mr I. MacDougall Mr E. Glavas Mr M. Jacobsen Former Executive KMP Ms A. Evans⁴ Mr D. Clegg⁵ 9,931,619 949,623 3,348,742 2,161,975 - 3,284,013 2,777,795 2,160,526 2,341,065 2,586,954 2,779,465 - 999,392 1,020,656 797,387 978,128 903,705 978,128 - 1,148,238 - - - - - - - - - - 1,666,575 11,044,509 482,951 466,672 595,807 - - 571,373 424,643 - 300,259 - 3,752,327 3,182,631 797,387 3,690,768 3,256,857 3,138,654 2,040,806 3,735,192 67 Director’s Statutory Report For the year ended 30 June 2020 4. Remuneration Report continued 4.8 2020 Remuneration Outcomes for Executive KMP continued 4.8.4 Movement in Performance Rights (PRs) continued The movement during the reporting period in the number of SARs granted held, directly, indirectly or beneficially, by each KMP, including their related parties, is as follows: 1. As a consequence of the Equity Incentive Plan amendments approved by shareholders at the Company’s Annual General Meeting held on 7 November 2019 (see note below), the terms of the SARs held by Mr Maxwell at 1 July 2019 were also amended. 2. SARs were granted to Mr Gordon when he was an Executive Director. 3. Ms Jalleh commenced as an Executive KMP on 9 August 2019. 4. Ms Evans ceased as an Executive KMP on 9 August 2019. 5. Mr Clegg ceased as a member of the Executive Leadership Team and as an Executive KMP on 31 December 2019. 6. SARs represent the right to receive a quantity of shares based on an amount equal to the difference in share price at grant date and test date. The terms of the SARs held at 1 July 2019 were amended following shareholder approval at the Company’s Annual General Meeting held on 7 November 2019 to provide that “good leavers” would retain rights held upon cessation of employment, subject to a Board discretion to determine otherwise. Rights were also amended to provide for pro-rata vesting of rights upon a change of control event on the basis of the proportion of the relevant performance period that has elapsed. 4.9 Nature of Non-Executive Director remuneration Non-Executive Directors are remunerated solely by way of fees and statutory superannuation. Their remuneration is reviewed annually to ensure that the fees reflect their responsibilities and the demands placed on them. Non-Executive Directors do not receive any performance-related remuneration. 4.9.1 Non-Executive Director Fee Structure The maximum aggregate remuneration pool for Non-Executive Directors, as approved by shareholders at the Company’s 2018 Annual General Meeting, is $1.25 million. The Non-Executive Directors’ fee structure for the reporting period was as follows (note there is no proposed change in Directors fees for 2021): Chairman* Member Board Audit Committee Risk & Sustainability Committee People and Remuneration Committee Nomination Committee $240,000 $115,000 $20,000 $10,000 $20,000 $10,000 $20,000 $10,000 $0 $5,000 *Where the Chairman of the Board is a member of a committee, he will not receive any additional committee fees. Remuneration paid to the Non-Executive Directors for the reporting period and for the previous reporting period is shown in the table in Section 4.9.3. The Company has entered into written letters of appointment with its Non-Executive Directors. The term of the appointment of a Non-Executive Director is determined in accordance with the Company’s Constitution and is subject to the provisions of the Constitution dealing with retirement, re-election and removal of Non-Executive Directors. The Constitution provides that all Non-Executive Directors of the Company are subject to re-election by shareholders by rotation every three years. The Company has entered into indemnity, insurance and access agreements with each of the Non-Executive Directors under which the Company will, on the terms set out in the agreement, provide an indemnity, maintain an appropriate level of Directors’ and Officers’ indemnity insurance and provide access to Company records. 68 Director’s Statutory Report For the year ended 30 June 2020 4. Remuneration Report continued 4.9.2 Directors & Executives movement in shares The movement during the reporting period in the number of ordinary shares in Cooper Energy held, directly, indirectly or beneficially, by each KMP, including their related parties, is as follows: Held at 1 July 2019 Purchases Directors Mr J. Conde AO Mr D. Maxwell Ms E. Donaghey Mr H. Gordon Mr J. Schneider Ms A. Williams Ms V. Binns¹ Mr T. Bednall¹ Executive KMP Mr A. Thomas Ms V. Suttell Ms A. Jalleh² Mr I. MacDougall Mr E. Glavas Mr M. Jacobsen Former Executive KMP Ms A. Evans³ Mr D. Clegg⁴ 859,093 17,416,881 160,000 2,673,781 1,016,594 179,444 - 44,499 4,328,970 40,600 - 2,677,157 1,712,405 - 1,821,381 135,000 - - - - - - - - - - - - - - - - Received on vesting of PRs & SARs - 1,457,484 - 422,357 - - 521,055 - - 499,687 371,367 - 262,114 - Sales Held at 30 June 2020 - - - - - - - - - - - - - - - - 859,093 18,874,365 160,000 3,096,138 1,016,594 179,444 - 44,499 4,850,025 40,600 - 3,176,844 2,083,772 - 2,083,495 135,000 1. Ms Binns and Mr Bednall were appointed to a casual vacancy as Non-Executive Directors during the reporting period. Their appointments are to be confirmed by shareholders at the 2020 annual general meeting scheduled for 12 November 2020. Mr Bednall held these shares at the time of his appointment as a Non-Executive Director (casual vacancy). 2. Ms Jalleh commenced as an Executive KMP on 9 August 2019. 3. Ms Evans ceased as an Executive KMP on 9 August 2019. 4. Mr Clegg ceased as a member of the Executive Leadership Team on 31 December 2019. Options No options were issued (or forfeited) during the year. 69 Director’s Statutory Report For the year ended 30 June 2020 4. Remuneration Report continued 4.9.3 Table of Directors’ remuneration for 2020 and 2019 financial years Short-term Base Salary STIP(a) Benefits Other Short-term Benefits(b) $ 219,178 191,781 $ - - $ - - Long Term Long Service Leave $ - - 884,245 510,298 74,755 17,601 824,469 622,946 80,904 34,796 137,131 91,324 136,225 118,722 136,986 118,722 40,335 30,863 136,225 118,722 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Executives Mr J. Conde AO Mr D. Maxwell Ms E. Donaghey Mr H. Gordon Mr J. Schneider Ms V. Binns(e) Mr T. Bednall(e) Ms A. Williams 2020 2019 2020 2019 2020 2019 2020 2019 2020 2019 2020 2020 2020 2019 Post Employment Share Based Remuneration(d) Superannuation(c) LTIP Total $ 20,822 18,219 21,003 20,531 13,027 8,875 12,941 11,278 13,014 11,279 3,832 2,932 12,941 11,279 $ - - $ 240,000 210,000 762,633 2,270,535 739,175 2,322,821 - - 150,158 100,199 31,926 181,092 93,091 223,091 - - - - - - 150,000 130,001 44,167 33,795 149,166 130,001 a) The STIP values noted for 2020 and 2019 include an under/over accrual representing the delta between the prior period accrual and what was actually paid in respect of that year. This variance will not exist in future periods. Refer to 4.6.3 for STIP amount earnt in FY20 which will be paid in FY21. b) Other short-term benefits include fringe benefits on accommodation, car parking and other benefits. c) Superannuation includes the amounts required to be contributed by the Company and does not include amounts salary sacrificed. d) In accordance with the requirements of the Accounting Standards, remuneration includes a proportion of the value of the equity-linked compensation determined as at the grant date of the PRs and progressively expensed over the vesting period. The amount allocated as remuneration is not relative to or indicative of the actual benefit (if any) that may ultimately be realised should the equity instruments vest. The value of the PRs was determined in accordance with AASB 2 Share-based Payments and is discussed in Section 4.7.1 above and in more detail in Note 27 of the Notes to the Financial Statements. PRs and SARs were granted to Mr Gordon when he was an Executive Director. e) Ms Binns and Mr Bednall were appointed to a casual vacancy as Non-Executive Directors on the dates above. Their appointments are to be confirmed by shareholders at the 2020 annual general meeting scheduled for 12 November 2020. End of remuneration report. 70 Director’s Statutory Report For the year ended 30 June 2020 5. Principal activities Cooper Energy is an upstream oil and gas exploration and production company whose primary purpose is to secure, find, develop, produce and sell hydrocarbons. These activities are undertaken either solely or via unincorporated joint ventures. There was no significant change in the nature of these activities during the year. 6. Operating and Financial Review Information on the operations and financial position of Cooper Energy and its business strategies and prospects is set out in the Operating and Financial Review. 7. Dividends The Directors do not recommend the payment of a dividend and no amount has been paid or declared by way of dividends since the end of the previous financial year, or to the date of this report. 8. Environmental regulation The Company is a party to various production, exploration and development licences or permits. In most cases, the licence or permit terms specify the environmental regulations applicable to oil and gas operations in the respective jurisdiction. The Group aims to ensure that it complies with the identified regulatory requirements in each jurisdiction in which it operates. There have been no significant known breaches of the environmental obligations of the Group’s licences or permits. 9. Likely developments Other than disclosed elsewhere in the Financial Report (including the Operating and Financial Review under the heading “Outlook”), further information about likely developments in the operations of the Group and the expected results of those operations in future financial years has not been included in this report because disclosure of the information would likely result in unreasonable prejudice to the consolidated entity. 10. Directors’ interests The relevant interest of each Director in ordinary shares and options over shares issued by the parent entity as notified by the Directors to the Australian Stock Exchange in accordance with S205G(1) of the Corporations Act 2001, at the date of this reports is as follows: Ordinary Shares Performance Rights Share Appreciation Rights Mr J. Conde AO Mr D. Maxwell Mr T. Bednall Ms V. Binns Ms E. Donaghey Mr H. Gordon Mr J. Schneider Ms A. Williams 859,093 18,874,365 44,499 Nil 160,000 3,096,138 1,016,594 179,444 Nil 3,989,401 Nil Nil Nil 180,683 Nil Nil Nil 11,044,509 Nil Nil Nil 466,672 Nil Nil 11. Share options and rights At the date of this report, there are no unissued ordinary shares of the parent entity under option. At the date of this report, there are 17,862,629 outstanding PRs and 48,280,025 SARs under the Equity Incentive Plan approved by shareholders at the 2019 AGM. During the financial year 5,096,588 shares were issued as a result of PRs exercised. At the date of this report, no PRs have vested and been exercised subsequent to 30 June 2020. 12. Events after financial reporting date Refer to Note 30 of the Notes to the Financial Statements. 13. Proceedings on behalf of the Company No person has applied to the Court under section 237 of the Corporations Act 2001 for leave to bring proceedings on behalf of the Company, or to intervene in any proceedings to which the Company is a party for the purpose of taking responsibility on behalf of the Company for all or part of the proceedings. 71 Director’s Statutory Report For the year ended 30 June 2020 14. Indemnification and insurance of directors and officers 14.1 Indemnification The parent entity has agreed to indemnify the current Directors and past Directors of the parent entity and of the subsidiaries, where applicable, against all liabilities (subject to certain limited exclusions) to persons (other than the Group or a related body corporate) which arise out of the performance of their normal duties as a Director or Executive Director unless the liability relates to conduct involving a lack of good faith. The parent entity has agreed to indemnify the Directors and Executive Directors against all costs and expenses incurred in defending an action that falls within the scope of the indemnity and any resulting payments. 14.2 Insurance premiums During the financial year, the parent entity has paid insurance premiums in respect of Directors’ and Officers’ liability and legal insurance contracts for current and former Directors and Officers including senior employees of the Parent entity. The insurance premium relates to costs and expenses incurred by the relevant officers in defending proceedings, whether civil or criminal and whatever their outcome and other liabilities that may arise from their position, with the exception of conduct involving a wilful breach of duty or improper use of information or position to gain a personal advantage. The insurance policy outlined above does not contain details of premiums paid in respect of individual Directors, Officers and senior employees of the parent entity. 15. Indemnification of auditors To the extent permitted by law, the Company has agreed to indemnify its auditors, Ernst & Young, as part of the terms of its audit engagement agreement against claims by third parties arising from the audit (for an unspecified amount) except in the case where the claim arises because of Ernst & Young’s negligent, wrongful or wilful acts or omissions. No payment has been made to indemnify Ernst & Young during or since the financial year. 16. Auditor’s independence declaration The auditor’s independence declaration is set out on page 126 and forms part of the Directors’ report for the financial year ended 30 June 2020. 17. Non-audit services The amounts paid and payable to the auditor of the Group, Ernst & Young and its related practices for non-audit services provided during the year was $187,915 (2019: $193,650). The directors are satisfied that the provision of non-audit services is compatible with the general standard of independence for auditors imposed by the Corporations Act 2001. The nature and scope of each type of non-audit service provided means that auditor independence was not compromised. 18. Rounding The Group is of a kind referred to in ASIC Corporations (Rounding in Financial/Directors’ Reports) Instrument 2016/191 dated 24 March 2016 and in accordance with that Legislative Instrument, amounts in the financial report have been rounded to the nearest thousand dollars, unless otherwise stated. This report is made in accordance with a resolution of the Directors. Mr John C. Conde AO Chairman Mr David P. Maxwell Managing Director Dated at Adelaide 31 August 2020 72 Cooper Energy Limited and its controlled entities Financial Statements For the year ended 30 June 2020 73 Consolidated Statement of Comprehensive Income For the year ended 30 June 2020 Revenue from oil and gas sales Cost of sales Gross profit Other income Other expenses Finance income Finance costs Loss before tax Income tax benefit Petroleum Resource Rent Tax expense Total tax benefit Loss after tax for the period attributable to shareholders Other comprehensive income/(expenditure) Items that will be reclassified subsequently to profit or loss Reclassification during the period to profit or loss of realised hedge settlements Fair value movements on interest rate swaps accounted for in a hedge relationship Income tax effect on fair value movement on derivative financial instrument Items that will not be reclassified subsequently to profit or loss Fair value movement on equity instruments at fair value through other comprehensive income Other comprehensive income/(expenditure) for the period net of tax Total comprehensive loss for the period attributable to shareholders Basic (loss)/earnings per share Diluted (loss)/earnings per share Notes 2 2 2 2 19 19 3 3 22 22 22 20 4 4 2020 $’000 78,139 (54,520) 23,619 2019 $’000 75,543 (43,570) 31,973 19,828 796 (147,546) (44,422) 1,728 (7,587) 3,398 (4,972) (109,958) (13,227) 25,575 (1,646) 23,929 10,040 (8,864) 1,176 (86,029) (12,051) (1,173) 2,140 (383) - (1,277) 383 (690) (106) (989) (1,883) (86,135) (13,934) Cents (5.3) (5.3) Cents (0.7) (0.7) The above Consolidated Statement of Comprehensive Income should be read in conjunction with the accompanying notes. 74 Consolidated Statement of Financial Position As at 30 June 2020 Assets Current Assets Cash and cash equivalents Trade and other receivables Prepayments Inventory Total Current Assets Non-Current Assets Other financial assets Property, plant and equipment Intangible assets Right-of-use assets Exploration and evaluation assets Oil and gas assets Deferred tax asset Total Non-Current Assets Total Assets Liabilities Current Liabilities Trade and other payables Provisions Lease liabilities Other financial liabilities Interest bearing loans and borrowings Total Current Liabilities Non-Current Liabilities Provisions Lease liabilities Government grants Interest bearing loans and borrowings Other financial liabilities Deferred Petroleum Resource Rent Tax Liability Total Non-Current Liabilities Total Liabilities Net Assets Equity Contributed equity Reserves Accumulated losses Total Equity Notes 2020 $’000 2019 $’000 5 6 7 8 21 10 11 16 12 13 3 9 15 16 21 18 15 16 17 18 21 3 20 20 20 131,583 19,996 6,106 822 164,289 21,169 3,346 426 158,507 189,230 21,532 16,366 1,878 9,738 159,078 615,980 46,836 871,408 21,740 4,580 36 - 152,268 613,198 20,757 812,579 1,029,915 1,001,809 21,183 19,902 1,045 - 26,000 68,130 374,671 12,004 - 203,438 3,642 16,948 610,703 44,533 11,131 - 1,758 - 57,422 276,789 - 430 213,680 3,482 16,293 510,674 678,833 568,096 351,082 433,713 475,862 11,180 (135,960) 351,082 474,397 9,247 (49,931) 433,713 The above Consolidated Statement of Financial Position should be read in conjunction with the accompanying notes. 75 Consolidated Statement of Changes in Equity For the year ended 30 June 2020 Balance at 1 July 2019 Loss for the period Other comprehensive expenditure Total comprehensive loss for the period Transactions with owners in their capacity as owners: Share based payments Transferred to issued capital Balance as at 30 June 2020 Balance at 1 July 2018 Loss for the period Other comprehensive expenditure Total comprehensive gain for the period Transactions with owners in their capacity as owners: Share based payments Transferred to issued capital Shares issued Balance as at 30 June 2019 Notes Issued Capital $’000 Reserves Accumulated Losses $’000 $’000 Total Equity $’000 474,397 9,247 (49,931) 433,713 - - - - 1,465 - (86,029) (86,029) (106) (106) - (106) (86,029) (86,135) 3,504 (1,465) - - 3,504 - 475,862 11,180 (135,960) 351,082 471,837 - - - - 2,217 343 474,397 9,925 - (1,883) (1,883) 3,422 (2,217) - 9,247 (37,880) (12,051) - (12,051) 443,882 (12,051) (1,883) (13,934) - - - 3,422 - 343 (49,931) 433,713 20 20 20 20 20 The above Consolidated Statement of Changes in Equity should be read in conjunction with the accompanying notes. 76 Consolidated Statement of Cash Flows For the year ended 30 June 2020 Cash Flows from Operating Activities Receipts from customers Payments to suppliers and employees Payments of exit provision Payments for restoration Petroleum Resource Rent Tax refund/(paid) Interest received Interest paid Net cash from operating activities Cash Flows from Investing Activities Transfers to term deposits Transfers from/(to) escrow proceeds receivable Payments for property, plant and equipment Payments for intangibles Receipts of consideration receivable Payments for exploration and evaluation Payments for oil and gas assets Interest paid Net cash flows used in investing activities Cash Flows from Financing Activities Repayment of principal portion of lease liabilities Proceeds from borrowings Transaction costs associated with borrowings Net cash flow from financing activities Net (decrease)/increase in cash held Net foreign exchange differences Cash and cash equivalents at 1 July Cash and cash equivalents at 30 June Notes 5 5 5 The above Consolidated Statement of Cash Flows should be read in conjunction with the accompanying notes. 2020 $’000 98,327 (49,532) - (2,544) 4,112 1,248 (3,549) 48,062 - - (5,947) (2,018) - 2019 $’000 79,873 (44,510) (3,133) (14,348) (530) 3,152 - 20,504 16 20,571 (2,571) (36) 894 (35,057) (11,962) (38,703) (180,010) (9,665) (11,015) (91,390) (184,113) (698) 11,284 (257) 10,329 - 92,290 (1,559) 90,731 (32,999) (72,878) 293 164,289 131,583 260 236,907 164,289 77 Notes to the Consolidated Financial Statements For the year ended 30 June 2020 Corporate information The consolidated financial report of Cooper Energy Limited and its controlled entities (“Cooper Energy” or “the Group”) for the year ended 30 June 2020 was authorised for issue in accordance with a resolution of the Directors on 31 August 2020. Cooper Energy Limited is a for profit company limited by shares incorporated and domiciled in Australia whose shares are publicly traded on the Australian Securities Exchange. The nature of the operations and principal activities of the Group are described in the Directors’ Statutory Report and Note 1. Basis of preparation The financial report is a general-purpose financial report, which has been prepared in accordance with the requirements of the Corporations Act 2001, Australian Accounting Standards and other authoritative pronouncements of the Australian Accounting Standards Board (AASB) and International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB). The financial report has also been prepared on a historical cost basis, except for equity instruments measured at fair value through other comprehensive income and derivative financial instruments measured at fair value through profit and loss. The financial report is presented in Australian dollars and under the option available to the Group under ASIC Corporations (Rounding in Financial/Directors’ Reports) Instrument 2016/191, all values are rounded to the nearest thousand dollars ($’000) unless otherwise stated. Australian Dollars is the functional currency of Cooper Energy Limited and all of its subsidiaries. Transactions in foreign currencies are initially recorded in the functional currency of the transacting entity at the exchange rates ruling at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies at the reporting date are translated at the rates of exchange ruling at that date. Exchange differences in the consolidated financial statements are taken to the income statement. A global pandemic was declared in March 2020 in relation to COVID-19. Price assumptions for oil and uncontracted gas have been revised to reflect the lower, post-COVID-19 prices, resulting in impairment recognised by the Group. Beyond the impact of the oil and gas prices, there has not been a significant impact on the operations of the Group. Further information on the Group’s response to COVID-19 has been included within the Operating and Financial Review. Going concern basis The consolidated financial statements have been prepared on the basis that the Group is a going concern, which contemplates continuity of normal operations and the realisation of assets and settlement of liabilities in the ordinary course of business. At the date of this report, it is the directors’ view that there are reasonable grounds to believe that the Group will continue as a going concern, having considered the matters set out below in the section titled Significant accounting judgements, estimates and assumptions “Funding and liquidity and progress towards Practical Completion of the Sole Gas Project”. Basis of consolidation The consolidated financial statements are those of the consolidated entity, comprising Cooper Energy Limited (“the parent entity”) and its controlled entities (“Cooper Energy” or “the Group”). The financial statements of subsidiaries are prepared for the same reporting period as the parent entity, using consistent accounting policies. All inter-company balances and transactions, income and expenses and profit and losses arising from intra-group transactions, have been eliminated in full. Subsidiaries are consolidated from the date on which the Group gains control of the subsidiary and cease to be consolidated from the date on which the Group ceases to control the subsidiary. Significant accounting judgements, estimates and assumptions In the process of applying the Group’s accounting policies, management is required to make judgements, estimates and assumptions that affect the reported amounts in the financial statements. Judgements, estimates and assumptions which are material to specific notes of the financial statements are below: Note 3 Income tax Note 15 Provisions Note 27 Share based payments Note 13 Oil and gas assets Note 16 Leases Note 14 Impairment Note 23 Interests in joint arrangements Judgements, estimates and assumptions which are material to the overall financial statements are below: Significant Accounting Judgements, Estimates and Assumptions Determination of recoverable hydrocarbons Estimates of recoverable hydrocarbons impact the asset impairment assessment, depreciation and amortisation rates and decommissioning and restoration provisions. Estimates of recoverable hydrocarbons are evaluated and reported by qualified petroleum reserves and resources evaluators in accordance with the ASX Listing Rules and the Group’s Hydrocarbon Guidelines (www.cooperenergy.com.au/our-company/corporate- governance-and-policies/hydrocarbon-reporting-policy). A technical understanding of the geological and engineering processes enables the recoverable hydrocarbon estimates to be determined by using forecasts of production, commodity prices, production costs, exchange rates, tax rates and discount rates. Recoverable hydrocarbon estimates may change from time to time if any of the forecast assumptions are revised. 78 Notes to the Consolidated Financial Statements For the year ended 30 June 2020 Significant accounting judgements, estimates and assumptions continued Significant Accounting Judgements, Estimates and Assumptions Funding and liquidity and progress towards Practical Completion of the Sole Gas Project The Sole Gas Project involved development of the Sole gas field by Cooper Energy and upgrading of the Orbost Gas Processing Plant (OGPP) to process Sole gas by the APA Group. Commissioning of the plant upgrade is yet to meet the performance standards for completion, which include demonstrated capacity to supply 68 TJ/day of Sole gas into the Eastern Gas Pipeline. Foaming in the absorber section of the plant has impaired output rates from the OGPP and been accompanied by fouling which required two shutdowns for maintenance prior to 30 June. The shutdowns and optimisation of operations by APA have resulted in improved plant performance but have not been sufficient for the plant to reach the required demonstrated capacity to achieve Practical Completion. APA and Cooper Energy are working collaboratively to improve plant performance to that required for the completion of commissioning. Subsequent to year-end the two companies announced a Transition Agreement (TA) which establishes the commercial framework for this collaboration and progress towards the commencement of firm gas supply and the practical completion of the OGPP. Under the agreement revenue and operating and capital costs will be shared while the OGPP proceeds to Practical Completion. Root cause analysis to identify the cause of the foaming, has been ongoing with involvement of the OGPP technology provider. APA has conducted minor plant modifications to improve performance, with further modifications planned for completion in September 2020. Planning is also underway for Phase 2 works to increase gas processing capacity, which will include the flexibility to reconfigure the two absorber vessels from a sequential to a parallel arrangement. The uncertainties associated with the progress to Practical Completion of the OGPP have required management to make significant accounting judgments and estimates. These are set out below. Progress of the OGPP and the Sole Gas project to Practical Completion The Phase 2 works (scope currently being finalised and subject to approval) are currently planned to commence in the December quarter (timing subject to supply chain and COVID-19 restrictions) for the resumption of production in the latter half of that quarter. The cost of the Phase 2 works has not been finalised, with current estimates being $15 million (Cooper Energy share $7.5 million). Commencement of term gas supply contracts from Sole has been deferred until the earlier of January 2021 or when permitted by the commencement of firm supply from the OGPP. Whilst OGPP has demonstrated capability to maintain stable supply of 40-45 TJ/day, Cooper Energy and APA are working to establish firm supply capability from the plant in advance of Practical Completion. The uncertainties associated with near term sales volumes, the extent to which those volumes will be sold at spot market prices versus GSA prices, costs of Phase 2 works, and timing of Practical Completion are all estimates which impact on the financial outcomes of the project. This has been considered in the impairment assessment performed for the Sole CGU. Further details are set out in Note 14. The progress towards Practical Completion also impacts on the accounting for the OGPP arrangement, including when the lease will be considered to commence. Further details, including the judgments involved, are set out in the New accounting standard and interpretation section that follows. Impacts on funding, liquidity and going concern: Cooper Energy’s development of the Sole gas field was funded through the Company’s Reserve Based Lending facility (RBL). The RBL was established principally to fund the Sole Gas Project capital expenditures and is secured against Group Borrowing Based Assets. A requirement under the RBL was for project completion to occur by 31 July 2020 with a long-stop date of 31 August 2020. Prior to 30 June 2020, the lending syndicate agreed to review and reset these dates once appropriate information has been made available pertaining to the additional technical works required to reach full processing capacity levels. All covenant requirements, which comprise primarily of information requests under the current terms, were met at 30 June 2020, or waived prior to that date. Accordingly, at 30 June 2020, amounts drawn under the RBL facility have been classified as current or non-current according to the repayment profile expected to apply under the terms of the Syndicated Facility Agreement (SFA) following completion of the Sole Gas Project. Refer Note 18. As at the date of the report, the Group has met and continues to meet all the requirements under the RBL. As noted, the lending syndicate has agreed to review and reset dates for Practical Completion once further information is made available. The lending syndicate has agreed to the provision of information requested in the fourth quarter of calendar 2020, when they will assess the information provided. The revised plan requires approval from Lenders. Failure to provide the information requested by Lenders within agreed timeframes, or failure to agree the technical plan and revised date for Project Completion is a review event under the SFA. The directors believe the Company will be able to provide the required information within agreed timeframes and reach agreement on the path to achieve project completion. This view has been made on the basis of technical work already progressed alongside APA as operator of the OGPP, commercial arrangements under a TA entered into with APA in August 2020 to facilitate full processing capacity levels, and the discussions with and continuing support from the Company’s lenders and gas customers. The Group holds significant cash balances of $131.6 million as at the end of the reporting period and has drawn debt of $229.4 million at that date. Cash flow forecasts for the Group, inclusive of the impact of the TA and under various scenarios that have been modelled, indicate that the Group can continue to meet its obligations and commitments including servicing debt for at least the next 12 months from the date of this report under the existing RBL facility. There is judgment involved in assessing the cash flows that will be required post Practical Completion as the RBL was designed to allow for a reset or redetermination at that time. Under the reasonably possible scenarios modelled, the Group maintains at all times the liquidity levels required under the RBL facility. Throughout commissioning of the OGPP, Cooper Energy has ensured the lending syndicate has been kept fully apprised of the commissioning status of the OGPP. While the facility does allow for a Review Event under certain circumstances, the mechanisms in the SFA requires Lenders to negotiate in good faith to agree outcomes under the existing structure of the RBL facility. The directors consider that if a Review Event is called, the possibility of an Event of Default occurring due to an inability of Cooper Energy and the Lenders to agree the relevant matters is remote. The syndicate holds security over the company’s 2P Reserves and Gas Sales Agreements with customers for offtake from Sole. In parallel to other workstreams, Cooper Energy has worked with customers to defer commencement of Gas Sales Agreements and is currently providing available volumes to customers at spot gas prices. It is the view of the directors based on current indications and advice that the lending syndicate will continue to support Cooper Energy and the Sole Gas Project, including the likely agreement of amendments to the RBL, as anticipated through the mechanisms in the SFA, once a technical plan is finalised and approved by APA and Cooper Energy. 79 New accounting standards and interpretations New standards, interpretations and amendments thereof, adopted by the Group The Group has adopted all of the new and revised Standards and Interpretations issued by the Australian Accounting Standards Board (the AASB) that are relevant to their operations and effective for the 2020 financial year. The Group has adopted AASB 16 Leases (AASB 16) and AASB Interpretation 23 Uncertainty Over Income Tax Treatments, issued by the Australian Accounting Standards Board (the AASB) that are relevant to its operations and effective for the current year. AASB 16 Leases The Group adopted AASB 16 from 1 July 2019. AASB 16 introduced a single, on-balance sheet accounting model for leases, which replaced AASB 117 Leases, AASB Interpretation 4 Determining Whether an Arrangement contains a Lease, AASB Interpretation 127 Evaluation of the Substance of Transactions Involving the Legal Form of a Lease and AASB Interpretation 115 Operating Leases – Incentives. Before the adoption of AASB 16, the Group classified each of its leases (as lessee) at the inception date as either a finance lease or an operating lease depending on whether risks and rewards incidental to ownership of the leased asset transferred to the Group. Under this approach only finance leases were recognised on the balance sheet from the lease commencement date. Upon adoption of AASB 16, the Group applied a single on-balance sheet recognition and measurement approach for all leases for which it is the lessee. The Group has also elected to use the recognition exemptions for lease contracts that, at the commencement date, have a lease term of 12 months or less and do not contain a purchase option (‘short-term leases’), and lease contracts for which the underlying asset is of low value (‘low-value assets’). In accordance with the transition provisions of AASB 16, the Group has adopted the modified retrospective method, measuring the right of use asset as equal to the lease liability, with the cumulative effect of adopting AASB 16 recognised as an adjustment to the opening balance of retained earnings at 1 July 2019, with no restatement of comparative information. This resulted in the Group recognising its property leases on balance sheet, finance costs in relation to the lease and depreciation of the right-of-use asset. These property leases were previously recognised as a lease expense in the Consolidated Statement of Comprehensive Income. The Group will recognise a depreciation expense and interest expense from the date the underlying asset is available for use. Transition impact At transition, the Group recognised a right-of-use asset representing its right to use the underlying asset and lease liabilities for all leases with a term of more than 12 months, excluding low-value leases. The group elected to apply the following available transition practical expedients: • Applied a single discount rate to a portfolio of leases with similar characteristics. The portfolio of leases is grouped based on similar remaining lease terms, similar class of underlying asset and similar economic environment. • Applied the short-term lease exemption to leases with a lease term that ends within 12 months at the date of initial recognition • Applied the exemption for leases of low-value assets. As a result, as at 1 July 2019, the following were the impacts of the transition: Assets: Right-of-use assets Liabilities: Trade and other payables Liabilities: Lease liabilities 1 July 2019 $’000 8,135 1,243 (9,378) The table below reconciles the operating lease commitments as at 30 June 2019 to the lease liabilities as at 1 July 2019. There was no impact on opening retained earnings. Operating lease commitments as at 30 June 2019 Weighted average incremental borrowing rate as at 1 July 2019 Discounted operating lease commitments at 1 July 2019 Add Payments in optional extension periods not recognised as at 30 June 2019 Lease liabilities as at 1 July 2019 There is no material impact on other comprehensive income and the basic and diluted EPS. 80 $’000 9,346 4.925% 5,240 4,138 9,378 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 New accounting standards and interpretations continued Orbost Gas Processing Plant Under AASB 16, the Group will recognise a right-of-use asset and corresponding lease liability in relation to the Orbost Gas Processing Plant (OGPP). The Sole Gas Processing Agreement creates a right-of-use asset and will be recognised at an amount equal to the corresponding lease liability. The Group will recognise a right-of-use asset and lease liability under AASB 16 for the Orbost Gas Processing Plant at the date the underlying asset is available for use. The Group currently expects the agreement, which was signed prior to 1 July 2019, to result in a right- of-use asset and lease liability of approximately $280 million to $310 million based on current information, with recognition to occur in the second half of the 2021 financial year once the asset is available for use. The final value that will be recorded for the right-of-use asset and lease liability is dependent on a number of factors that will be known at the time the asset is available for use. These amounts may change depending on production volumes per annum, the timing of commencement of the lease, annual indexation to be applied and other factors. This does not contemplate any payments associated with processing gas through the OGPP under the transition agreement entered into with APA on 20 August 2020. AASB 16 requires that the lessee’s rate implicit in the lease arrangement be used to measure the present value of the lease liability, unless that cannot be determined, in which case the incremental borrowing rate should be used. In determining the discount rate applicable to the Orbost Gas Processing Plant lease liability, the Group will use the rate implicit in the lease. The contract includes non-lease payments for services which do not form part of the lease liability and will be recognised as production costs as incurred. The lease charge is calculated based on the lease component payment required under the agreements. AASB Interpretation 23 - Uncertainty Over Income Tax Treatments The Group has applied AASB Interpretation 23 from 1 July 2019. The recognition, measurement and disclosure requirements of the standard have been applied to any uncertain tax treatments. The Group has determined it is probable that the current estimated treatment will be accepted by the Australian Taxation Office and the tax provision calculation is in line with tax filings. Notes to the financial statements The notes include information which is required to understand the financial statements and is material and relevant to the operations, financial position and performance of the Group. They include applicable accounting policies applied and significant judgements, estimates and assumptions made. Specific accounting policies are disclosed in the respective notes to the financial statements. The notes are organised into the following sections: Group performance Working capital Capital employed Funding and risk management Group structure Other information Provides additional information regarding financial statement lines that are most relevant to explaining the Group’s performance during the period. Provides additional information regarding financial statement lines that are most relevant to explaining the assets used to generate the Group’s trading performance during the period. Provides additional information regarding financial statement lines that are most relevant to explaining the capital investments made that allows the Group to generate its operating result during the period and liabilities incurred as a result. Provides additional information regarding financial statement lines that are most relevant to explaining the Group’s funding sources. This section also provides information relating to the Group’s exposure to various financial risks, its impact on the financial position and performance of the Group and how these risks are managed. Summarises how the group structure affects the financial position and performance of the Group as a whole. Includes other information that is disclosed to comply with relevant accounting standards and other pronouncements, but is not directly related to the individual line items in the financial statement. 81 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 Group Performance 1. Segment reporting Identification of reportable segments and types of activities The Group identified its reportable segments to be Cooper Basin, South-East Australia (based on the nature and geographic location of the assets) and Corporate and Other. This forms the basis of internal Group reporting to the Managing Director who is the chief operating decision maker for the purpose of assessing performance and allocating resources between each segment. Revenue and expenses are allocated by way of their natural expense and income category. Other prospective opportunities are also considered from time to time and, if they are secured, will then be attributed to the segment where they are located, or a new segment will be established. The following are reportable segments: Cooper Basin Exploration and evaluation of oil and gas and production and sale of crude oil in the Group’s permits within the Cooper Basin. Revenue is derived from the sale of crude oil to IOR Energy Pty Ltd and a consortium of buyers made up of Santos Limited (and its subsidiaries), Delhi Petroleum Pty Ltd and Lattice Energy Limited. South-East Australia The South-East Australia segment primarily consists of the Sole Gas Project, Manta Gas Project and the Group’s interest in the operated Casino Henry and non-operated Minerva producing gas assets. Revenue is derived from the sale of gas and condensate to four customers. The segment also includes exploration and evaluation and care and maintenance activities ongoing in the Otway and Gippsland basins. Corporate and Other The Corporate segment includes the revenue and costs associated with the running of the business and includes items which are not directly allocable to the other segments. Accounting policies and inter-segment transactions The accounting policies used by the Group in reporting segments internally is the same as those contained in the financial statements. Segments 30 June 2020 Revenue from oil and gas sales to external customers Total revenue Segment result before interest, tax, depreciation, amortisation and impairment Depreciation and amortisation Impairment Net finance (costs)/income Profit/(loss) before tax Income tax benefit Petroleum Resource Rent Tax expense Net profit/(loss) after tax Segment assets Segment liabilities Additions of non-current assets Exploration and evaluation assets Oil and gas assets Property, plant and equipment Intangibles Right-of-use assets Cooper Basin $’000 14,558 14,558 6,486 (3,573) (7,836) (95) (5,018) - - (5,018) 14,969 8,731 6,802 5,579 - - - South-East Australia Corporate and Other Consolidated (restated) $’000 $’000 $’000 63,581 63,581 42,937 (23,234) (99,662) (3,943) (83,902) - (1,646) (85,548) 802,263 421,656 85,651 48,610 11,593 - - - - (17,094) (2,123) - (1,821) (21,038) - - (21,038) 212,683 248,446 - - 1,481 2,017 2,723 6,266 78,139 78,139 32,329 (28,930) (107,498) (5,859) (109,958) 25,575 (1,646) (86,029) 1,029,915 678,833 92,453 54,189 13,074 2,017 2,723 164,456 Total additions of non-current assets 12,381 145,809 82 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 1. Segment reporting continued Accounting policies and inter-segment transactions continued Segments 30 June 2019 Revenue from oil and gas sales to external customers Total revenue Segment result before interest, tax, depreciation, amortisation and impairment Depreciation and amortisation Net finance (costs)/income Profit/(loss) before tax Income tax benefit Petroleum Resource Rent Tax expense Net profit/(loss) after tax Segment assets Segment liabilities Additions of non-current assets Exploration and evaluation assets Oil and gas assets Property, plant and equipment Intangibles Cooper Basin $’000 South-East Australia Corporate and Other Consolidated (restated) $’000 $’000 $’000 23,283 23,283 14,168 (1,628) (101) 12,439 - - 12,439 19,059 6,719 2,015 1,831 - - 52,260 52,260 7,126 (16,713) (4,871) (14,458) - (8,864) (23,322) 765,765 342,798 52,881 234,914 184 - - - (13,778) (828) 3,398 (11,208) - - (11,208) 216,985 218,579 - - 2,579 36 2,615 75,543 75,543 7,516 (19,169) (1,574) (13,227) 10,040 (8,864) (12,051) 1,001,809 568,096 54,896 236,745 2,763 36 294,440 Total additions of non-current assets 3,846 287,979 In 2020, revenue from two customers amounted to $31.9 million, and $27.3 million respectively in the South-East Australia segment and $17.9 million from one customer in the Cooper Basin segment. In 2019, revenue from two customers amounted to $42.2 million, and $5.4 million respectively in the South-East Australia segment and $22.7 million from one customer in the Cooper Basin segment. 2. Revenues and expenses Revenue from oil and gas sales Revenue from contracts with customers Oil revenue from contracts with customers Gas revenue from contracts with customers Total revenue from contracts with customers Other revenue Fair value movement on crude oil receivables Fair value movement on commodity price options Total other revenue Total revenue from oil and gas sales Notes 2020 $’000 2019 $’000 15,563 63,581 79,144 (1,005) - (1,005) 78,139 23,744 52,260 76,004 (445) (16) (461) 75,543 83 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 2020 $’000 19,800 28 - - 19,828 (26,511) (1,203) (26,452) (354) (54,520) (693) (15,123) (828) (176) (1,120) (3,597) (14,056) (3,100) 2019 $’000 - - 774 22 796 (23,327) (1,902) (18,179) (162) (43,570) (762) (11,933) (828) - - (590) (26,205) (1,360) - (358) 236 1,623 (4,245) (44,422) (17,002) (3,422) (853) (21,277) 14 (107,498) (123) - 119 (1,351) (147,546) (20,412) (3,504) (1,264) (25,180) - (951) 2. Revenues and expenses continued Notes Other income Liquidated damages¹ Other Gain on exit provision Gain on movement of consideration receivable Total other income Cost of sales Production expenses² Royalties Amortisation of oil and gas assets Depreciation of property, plant and equipment Total cost of sales Other expenses Selling expense² General administration² Depreciation of property, plant and equipment Amortisation of intangibles Depreciation of right-of-use assets Care and maintenance Restoration expense Exploration and evaluation expense Impairment expense Fair value adjustment of success fee liability Fair value movement on oil price derivatives Realised and unrealised foreign currency translation (loss)/gain Other (including new ventures)² Total other expenses Employee benefits expense included in general administration Director and employee benefits Share based payments Superannuation expense Total employee benefits expense (gross) Lease payments included in general administration Minimum lease payment – operating lease (gross) 1. Liquidated damages received from APA in relation to the Sole delay 2. Comparatives have been restated for reclassification between expense categories 84 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 2. Revenues and expenses continued Accounting Policy Revenue from contracts with customers Revenue from contracts with customers is recognised at the point in time when control of the crude oil, natural gas or liquids is transferred to the customer, at an amount that reflects the consideration to which the Group expects to be entitled in exchange for those goods. This is generally when the product is transferred to the delivery point specified in the individual customer contract. The Group’s performance obligations are considered to relate only to the sale of the crude oil, natural gas or liquids, with each barrel of crude oil or GJ of natural gas considered to be a separate performance obligation under the contractual arrangements in place. The Group has concluded that it is the principal in all of its revenue arrangements since it controls the goods before transferring them to the customer. Under the terms of the relevant joint operating arrangements the Group is entitled to its participating share in the crude oil, natural gas or liquids based on the Group’s entitlement interest. Revenue from contracts with customers is recognised based on the actual volumes sold to customers. The Group’s sales of natural gas are predominantly based on contracted prices, while crude oil and liquids transactions are priced based on market prices. The crude oil sales price is the Tapis crude oil price, adjusted for a quality differential. The crude oil sales contain provisional pricing. Revenue from contracts with customers is recognised based on the provisional pricing at the date of delivery, with the price estimate based on the forward curve. The difference between the estimated price and the price ultimately achieved for the sale of the crude oil transaction is recognised as a movement in the fair value of the receivable in accordance with AASB 9 Financial Instruments. This amount is presented as other revenue in Note 2 as these movements are not within the scope of AASB 15 Revenue from Contracts with Customers. 3. Income tax Consolidated Statement of Comprehensive Income Current income tax Current year Deferred income tax Origination and reversal of temporary differences Over provision in respect of prior year income tax Income tax benefit Current Petroleum Resource Rent Tax Current year Adjustments in respect of prior year income tax Deferred Petroleum Resource Rent Tax Origination and reversal of temporary differences Petroleum Resource Rent Tax expense Total tax benefit/(expense) 2020 $’000 2019 $’000 (504) (504) 26,070 9 26,079 25,575 (5,686) 3,299 (2,387) 741 741 (1,646) 23,929 - - 7,522 2,518 10,040 10,040 (3,760) (492) (4,252) (4,612) (4,612) (8,864) 1,176 85 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 3. Income tax continued Reconciliation between tax expense and pre-tax net profit Accounting (loss)/profit before tax from continuing operations Income tax using the domestic corporation tax rate of 30% (2019: 30%) (Increase)/decrease in income tax expense due to: Deductible expenditure Non-assessable income Non-deductible expenditure Adjustments in respect to current income tax of previous years Recognition of royalty related income tax benefits Permanent difference arising from impairment expense Other Income tax benefit Petroleum Resource Rent Tax expense Total tax benefit/(expense) Income tax recognised in other comprehensive income Fair value movement on derivative financial instruments Income tax using the domestic corporation tax rate of 30% (2019: 30%) Tax Consolidation 2020 $’000 2019 $’000 (109,958) 32,987 (13,227) 3,968 - - (187) 9 197 (8,112) 681 25,575 (1,646) 23,929 - - 161 232 (1,469) 2,518 1,383 - 3,247 10,040 (8,864) 1,176 383 383 Cooper Energy Limited and its 100% owned Australian resident subsidiaries are consolidated for Australian income tax purposes with Cooper Energy Limited being the head entity of the tax consolidated group. Members of the Group entered into a tax sharing arrangement in order to allocate income tax expense to the wholly-owned subsidiaries. In addition, the agreement provides for the allocation of income tax liabilities between the entities should the head entity default on its tax payment obligations. Members of the tax consolidated group have entered into a tax funding agreement. The tax funding agreement requires members of the tax consolidated group to make contributions to the head Company for tax liabilities and deferred tax balances arising from transactions occurring after the implementation of tax consolidation. Contributions are payable following the payment of the liabilities by Cooper Energy Limited. The assets and liabilities arising under the tax funding agreement are recognised as inter-company assets and liabilities with a consequential adjustment to income tax expense or benefit. In addition, the agreement provides for the allocation of income tax liabilities between the entities should the head entity default on its tax payment obligations or upon leaving the Group. The current and deferred tax amounts are measured in a systematic manner that is consistent with the broad principles in AASB 112 Income Taxes. Unrecognised temporary differences At 30 June 2020, there are no unrecognised temporary differences associated with the Group’s investments in subsidiaries, as the Group has no liability for additional taxation should unremitted earnings be remitted (2019: $nil). Franking Tax Credits At 30 June 2020 the parent entity had franking tax credits of $42.9 million (2019: $42.9 million). The fully franked dividend equivalent is $142.9 million (2019: $142.9 million). Petroleum Resource Rent Tax (PRRT) Cooper Energy Limited has recognised a Deferred Tax Liability for Petroleum Resource Rent Tax (PRRT) of $16.9 million (2019: $16.3 million) relating to PRRT on the Group’s producing gas assets. The Group has not recognised a Deferred Tax Asset for PRRT of $29.0 million (2019: $19.1 million). In the current year, this is in respect of the Sole Gas Project, and the Deferred Tax Asset for Sole will be recognised when it is probable that the undeducted expenditure will be able to be utilised. From 1 July 2019, there was a change in the PRRT legislation so that onshore petroleum projects will no longer be subject to PRRT. The Group has significant levels of undeducted expenditure in respect of the Cooper Basin oil producing assets that will not be utilised. 86 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 3. Income tax continued Income Tax Losses (a) Revenue Losses A Deferred Tax Asset has been recognised for the year ended 30 June 2020 of $35.0 million (2019: $23.6 million). (b) Capital Losses Cooper Energy has not recognised a Deferred Tax Asset for Australian income tax capital losses of $15.5 million (2019: $15.5 million) on the basis that it is not probable that the carried forward capital losses will be utilised against future assessable capital profits. Capital losses have been utilised in the prior year to offset the capital gain generated from the sale of the Orbost Gas Processing Plant and the receipt of funds from exited joint venture parties for the BMG abandonment. Deferred income tax from corporate tax Deferred income tax at 30 June relates to: Deferred tax liabilities Trade and other receivables Oil and gas assets Exploration and evaluation Property, plant and equipment Other Unrealised currency translation gain Deferred tax assets Leases Provision for employee entitlements Provisions Other Capital raising costs Tax losses Deferred tax benefit Consolidated Statement of Financial Position Consolidated Statement of Comprehensive Income 2020 $’000 2019 $’000 2020 $’000 2019 $’000 (62) 33,974 17,118 40 83 - 2,240 20,325 8,293 40 103 - 2,302 (13,649) (8,825) - 20 - 1,343 (4,172) (4,211) (40) (62) - 51,153 31,001 (20,152) (7,142) 993 1,422 53,392 5,903 1,213 35,066 97,988 - 2,082 18,410 5,377 2,261 23,628 51,758 993 (660) - 259 34,982 13,808 525 (1,048) 11,438 46,230 26,078 2,064 (965) 2,016 17,182 10,040 Deferred tax asset from corporate tax 46,836 20,757 Deferred income tax from PRRT Deferred income tax at 30 June relates to: Deferred tax liabilities Oil and gas assets Deferred tax (expense) 16,948 16,293 25 25 (4,612) (4,612) Deferred tax liability from PRRT 16,948 16,293 87 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 3. Income tax continued Accounting Policy Current tax assets and liabilities for the current and prior periods are measured at the amount expected to be recovered from or paid to the taxation authorities based on tax rates and tax laws that are enacted or substantively enacted by the reporting date. Deferred income tax is recognised on all temporary differences, except for: • the initial recognition of an asset or liability that affects neither the accounting profit nor taxable profit or loss; or • the taxable temporary difference is associated with investments in subsidiaries, associates or interests in joint ventures, and the timing of the reversal of the temporary difference can be controlled and it is probable that the temporary difference will not reverse in the foreseeable future. Deferred income tax assets are recognised for all deductible temporary differences, carry-forward of unused tax assets and unused tax losses, to the extent that it is probable that future taxable profit will be available against which the deductible temporary differences and the carry-forward of unused tax credits and unused tax losses can be utilised. The carrying amount of deferred income tax assets is reviewed at each reporting date and reduced to the extent that it is no longer probable that sufficient taxable profit will be available to allow all or part of the deferred income tax asset to be utilised. Unrecognised deferred income tax assets are reassessed at each reporting date and are recognised to the extent that it has become probable that future taxable profit will allow the deferred tax asset to be recovered. Deferred income tax assets and liabilities are measured at the tax rates that were expected to apply to the year when the asset is realised or the liability is settled, based on tax rates and tax laws that have been enacted or substantively enacted at the reporting date. Income taxes relating to items recognised directly in equity are recognised in equity and not in profit or loss. Deferred tax assets and deferred tax liabilities are offset only if a legally enforceable right exits to offset current tax assets against current tax liabilities and the deferred tax asset and liabilities relate to the same taxable entity and the same taxation authority. Where allowable by initial recognition exemptions, deferred tax assets and deferred tax liabilities that arise on acquisition are not recognised. Petroleum Resource Rent Tax (PRRT) For PRRT purposes, the impact of future augmentation on expenditure is included in the determination of future taxable profits when assessing the extent to which a deferred tax asset can be recognised in the statement of financial position. Deferred tax assets are reduced to the extent that it is no longer probable that the related tax benefit will be realised. Goods and Services Taxes (GST) Revenues, expenses and assets are recognised net of the amount of GST. Receivables and payables are stated inclusive of the amount of GST receivable or payable. The net amount of GST recoverable from, or payable to, the taxation authority is included as part of receivables or payables in the Consolidated Statement of Financial Position. Commitments and contingencies are disclosed net of the amount of GST recoverable from, or payable to, the taxation authority. Cash flows are included in the Cash Flow Statement on a net basis and the net GST component of cash flows arising from investing and financing activities, which is recoverable from, or payable to, the taxation authority, are classified as operating cash flows. Significant Accounting Judgements, Estimates and Assumptions The Group has a Tax Risk Management Framework which outlines how the direct and indirect tax obligations of Cooper Energy Limited are met from an operational, governance and tax risk management perspective. Management judgements are made in relation to the types of arrangements considered to be a tax on income (PRRT) in contrast to an operating cost. Judgement is also made in assessing whether deferred tax assets and certain deferred tax liabilities are recognised on the Consolidated Statement of Financial Position. Deferred tax assets, including those arising from un-recouped tax losses, capital losses, and temporary differences arising from the Petroleum Resource Rent Tax legislation, are recognised only where it is considered more likely than not they will be recovered, which is dependent on the generation of sufficient future taxable profits. Future taxable profits are estimated by using Board approved internal budgets and forecasts. Judgements are also required about the application of income tax legislation. These judgements and assumptions are subject to risk and uncertainty, hence there is a possibility changes in circumstances will alter expectation, which may impact the amount of deferred tax assets and deferred tax liabilities recognised on the Consolidated Statement of Financial Position and the amount of other tax losses and temporary differences not yet recognised. In such circumstances, some or all of the carrying amounts of recognised deferred tax assets and liabilities may require adjustment, resulting in a corresponding credit or charge to the Consolidated Statement of Comprehensive Income. 88 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 4. Earnings per share The following reflects the net (loss)/profit and share data used in the calculations of earnings per share: Net (loss)/profit after tax attributable to shareholders 2020 $’000 2019 $’000 (86,029) (12,051) 2020 Thousands 2019 Thousands Weighted average number of ordinary shares used in calculating basic earnings per share 1,624,260 1,611,905 Dilutive performance rights and share appreciation rights1 - - Weighted average number of ordinary shares used in calculating dilutive earnings per share 1,624,260 1,611,905 Basic loss per share for the period (cents per share) Diluted loss per share for the period (cents per share) (5.3) (5.3) (0.7) (0.7) 1. The weighted average number of potentially dilutive shares at 30 June 2020 is 12.4 million (2019: 24.6 million) At 30 June 2020 there exist performance rights and share appreciation rights that if vested, would result in the issue of additional ordinary shares over the next three years. In the current period, these potential ordinary shares are considered antidilutive as their conversion to ordinary shares would reduce the loss per share. Accordingly, they have been excluded from the dilutive earnings per share calculation. There have been no other transactions involving ordinary shares or potential ordinary shares between the reporting date and the date of completion of these financial statements. Accounting Policy Basic earnings per share are calculated as net profit attributable to shareholders divided by the weighted average number of ordinary shares. Diluted earnings per share is calculated as net profit attributable to shareholders adjusted for the after tax effect of dilutive potential ordinary shares that have been recognised as expenses during the period divided by the weighted average number of ordinary shares and dilutive potential ordinary shares. 89 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 Working Capital 5. Cash and cash equivalents and term deposits Current Assets Cash at bank and in hand Term deposits at bank Cash and cash equivalents Reconciliation of net profit to net cash flows from operating activities Net (loss)/profit after tax Add/(deduct) non-cash items: Amortisation of oil and gas assets Depreciation of property, plant and equipment Amortisation of intangibles Depreciation of right-of-use assets Impairment expense Exploration and Evaluation expense Restoration expense Share based payments Finance costs Foreign exchange (gain)/loss Other non-cash movements 2020 $’000 111,567 20,016 131,583 2019 $’000 136,539 27,750 164,289 2020 $’000 2019 $’000 (87,204) (12,051) 26,452 1,182 176 1,120 107,498 3,100 14,056 3,504 4,038 (293) 1,804 18,179 990 - - - 1,360 26,205 3,422 4,972 (778) (656) Net cash from operating activities before changes in assets or liabilities 75,433 41,643 Add/(deduct) changes in operating assets or liabilities: Decrease in trade and other receivables (Increase)/decrease in inventories Increase in prepayments Decrease in deferred taxes Increase/(decrease) in trade and other payables Decrease in provisions Net cash from operating activities Reconciliation of liabilities arising from financing activities Balance at beginning of period Financing cash flows¹ Non-cash financing movements² Balance at end of period 1,173 (396) (3,760) (25,424) 2,750 (1,714) 48,062 Borrowings Lease Liabilities 2020 $’000 213,680 11,284 4,474 229,438 2019 $’000 116,923 92,290 4,467 213,680 2020 $’000 - (698) 13,747 13,049 4,694 41 (560) (4,486) (7,169) (13,659) 20,504 2019 $’000 - - - - 1. Financing cash flows consist of the net amount of proceeds from borrowings and repayment of lease liabilities in the statement of cash flows 2. The movement in borrowings is amortisation of prepaid financing costs, and movement in lease liabilities represents the lease liability recognised on adoption of AASB 16 Leases. Accounting Policy Cash and cash equivalents in the Consolidated Statement of Financial Position comprise cash at bank and short-term deposits for periods of up to three months or subject to insignificant changes in value. For the purposes of the Statement of Cash Flows, cash and cash equivalents includes cash and term deposits as defined above, net of outstanding bank overdrafts. Cash held in escrow with associated restrictions whereby the Group cannot use that cash for operational purposes as it deems appropriate is not included in cash and cash equivalents. 90 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 6. Trade and other receivables Current Assets Trade receivables Accrued revenue Interest receivable 2020 $’000 17,783 2,176 37 19,996 2019 $’000 9,474 11,349 346 21,169 Expected credit losses in respect of trade and other receivables is set out in Note 21. Accounting Policy Trade receivables are non-interest bearing and generally have 30 to 90 day terms. Trade receivables are initially recognised at the transaction price as defined by AASB 15 Revenue from Contracts with Customers and subsequently carried at amortised cost less any allowances for expected credit loss. An allowance for expected credit loss is recognised using the simplified approach which permits the use of the lifetime expected loss provision for all trade receivables. Bad debts are written off when identified. 7. Prepayments Insurance Prepaid cash calls to joint arrangements Other prepayments 8. Inventory Spares and parts 2020 $’000 1,530 4,384 192 6,106 2020 $’000 822 2019 $’000 884 25 2,437 3,346 2019 $’000 426 All inventory items are carried at cost in the current and previous financial years. Accounting Policy Inventories are carried at the lower of their cost or net realisable value. Inventories held by the Group are in respect of spares and parts involved in drilling operations. Items held as insurance or capital spares are treated as part of property, plant and equipment. 9. Trade and other payables Trade payables Accruals (capital and operating expenditure) Deferred lease incentive Accounting Policy 2020 $’000 14,844 6,339 - 21,183 2019 $’000 5,046 36,598 2,889 44,533 Trade payables are non-interest bearing and carried at amortised cost. The amounts represent liabilities for goods and services provided during the financial year, but not yet settled at the balance sheet date. Accruals represent unbilled goods or services. 91 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 Capital Employed 10. Property, plant and equipment Reconciliation of carrying amounts at beginning and end of period: Carrying amount at beginning of period Assets acquired Additions Disposals/written off Depreciation Carrying amount at end of period Cost Accumulated depreciation Carrying amount at end of period Accounting Policy Production assets Corporate assets Total 2020 $’000 2019 $’000 2020 $’000 543 8,674 2,813 - (354) 11,676 15,567 (3,891) 11,676 521 - 184 - (162) 543 4,080 (3,537) 543 4,037 - 1,481 - (828) 4,690 7,556 (2,866) 4,690 2019 $’000 2,343 - 2,579 (57) (828) 4,037 6,075 (2,038) 4,037 2020 $’000 4,580 8,674 4,294 - (1,182) 16,366 23,123 (6,757) 16,366 2019 $’000 2,864 - 2,763 (57) (990) 4,580 10,155 (5,575) 4,580 Property, plant and equipment comprises office and IT equipment, leasehold improvements and the Athena Gas Plant, and is stated at historical cost less accumulated depreciation and any accumulated impairment losses (refer to Note 14 for impairment policy). Historical cost includes expenditure that is directly attributable to the acquisition of the items. Subsequent costs are included in the asset’s carrying amount or recognised as a separate asset, as appropriate, only when it is probable that future economic benefits associated with the item will flow to the Group and the cost of the item can be measured reliably. Repairs and maintenance are recognised in the Consolidated Statement of Comprehensive Income as incurred. Depreciation on property plant and equipment is calculated at between 7.5% and 37.5% per annum using the diminishing value method over the asset’s estimated useful lives. The assets’ residual values and useful lives are reviewed, and adjusted if appropriate, at each reporting date. An item of property, plant and equipment is derecognised upon disposal or when no further future economic benefits are expected from its use. Any gains or losses arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the net carrying amount of the asset) is included in the Consolidated Statement of Comprehensive Income. 11. Intangible assets Reconciliation of carrying amounts at beginning and end of period: Carrying amount at beginning of period Additions Amortisation Carrying amount at end of period Cost Accumulated depreciation Carrying amount at end of period Accounting Policy 2020 $’000 36 2,018 (176) 1,878 2,054 (176) 1,878 2019 $’000 - 36 - 36 36 - 36 Intangible assets comprises software and is stated at historical cost less accumulated amortisation and any accumulated impairment losses. Historical cost includes expenditure that is directly attributable to the acquisition of the items. Intangible assets are determined to have a finite useful life and are amortised over their useful lives and tested for impairment whenever there is an indicator of impairment. Amortisation on intangibles is calculated at 20% per annum using the straight line method. The assets’ residual values and useful lives are reviewed, and adjusted if appropriate, at each reporting date. 92 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 12. Exploration and evaluation assets Reconciliation of carrying amounts at beginning and end of period Carrying amount at beginning of period Additions Exploration and evaluation expense Impairment Transfer to oil and gas assets Carrying amount at end of period¹ Notes 14 2020 $’000 152,268 92,453 (3,100) (79,398) (3,145) 159,078 2019 $’000 98,732 54,896 (1,360) - - 152,268 1. Recoverability is dependent on the successful development and commercial exploration or sale of the respective areas of interest. Accounting Policy Exploration and evaluation expenditure include costs incurred in the search for hydrocarbon resources and determining the commercial viability in each identifiable area of interest. Exploration and evaluation expenditure is accounted for in accordance with the successful efforts method and is capitalised to the extent that: i. the rights to tenure of the areas of interest are current and the Group controls the area of interest in which the expenditure has been incurred; and ii. such costs are expected to be recouped through successful development and exploration of the area of interest, or alternatively by its sale; or iii. exploration and evaluation activities in the area of interest have not at the reporting date: a. reached a stage which permits a reasonable assessment of the existence or otherwise of economically recoverable reserves; and b. active and significant operations in, or in relation to, the area of interest are continuing. An area of interest refers to an individual geological area where the potential presence of an oil or a natural gas field is considered favourable or has been proven to exist, and in most cases, comprises an individual prospective oil or gas field. Exploration and evaluation expenditure which does not satisfy these criteria is written off. Specifically, costs carried forward in respect of an area of interest that is abandoned or costs relating directly to the drilling of an unsuccessful well are written off in the year in which the decision to abandon is made or the results of drilling are concluded. The success or otherwise of a well is determined by reference to the drilling objectives for that well. For successful wells, the well costs remain capitalised on the Consolidated Statement of Financial Position as long as sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. Any appraisal costs relating to determining commercial feasibility are also capitalised as exploration and evaluation assets. A regular review is undertaken of each area of interest to determine the appropriateness of continuing to carry forward costs in relation to that area of interest. Where facts and circumstances suggest that the carrying amount exceeds the recoverable amount, or where one of the specific factors set out in i-iii above are no longer met, the Group will test for impairment in accordance with the impairment policy stated in Note 14. Where an ownership interest in an exploration and evaluation asset is exchanged for another, the transaction is recognised by reference to the carrying value of the original interest. Any cash consideration paid, including transaction costs, is accounted for as an acquisition of exploration and evaluation assets. Any cash consideration received, net of transaction costs, is treated as a recoupment of costs previously capitalised with any excess accounted for as a gain on disposal of non-current assets. Where a discovered oil or gas field enters the development phase the accumulated exploration and evaluation expenditure is tested for impairment and then transferred to oil and gas assets. 13. Oil and gas assets Reconciliation of carrying amounts at beginning and end of period: Carrying amount at beginning of period Additions Transferred from exploration and evaluation Amortisation Impairment Carrying amount at end of period Cost Accumulated amortisation & impairment Carrying amount at end of period Notes 2020 $’000 2019 $’000 14 613,198 54,189 3,145 (26,452) (28,100) 615,980 769,575 (153,595) 615,980 394,632 236,745 - (18,179) - 613,198 712,241 (99,043) 613,198 93 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 13. Oil and gas assets continued Accounting Policy Oil and gas assets are carried at cost including construction, installation of infrastructure such as roads, pipelines or umbilicals and the cost of development of wells. Any restoration assets arising as a result of recognition of a restoration provision is also included in the carrying amount of oil and gas assets. Subsequent costs are included in the asset’s carrying amount or recognised as a separate asset, as appropriate, only when it is probable that future economic benefits associated with the item will flow to the Group and the cost of the item can be measured reliably. All other repairs and maintenance are charged to the Consolidated Statement of Comprehensive Income as incurred. Oil and gas assets are amortised on the Units of Production basis using the latest approved estimate of Proved and Probable (2P) Reserves and future development cost estimates. Amortisation is charged only once production has commenced. No amortisation is charged on areas under development where production has not commenced. Oil and gas assets are subject to impairment testing, refer to Note 14. Significant Accounting Judgements, Estimates and Assumptions Estimation of oil and gas asset expenditure Capitalised oil and gas assets for the construction of major projects or ongoing well construction activities include accruals in relation to the value of work done. These remain estimates until the contractual arrangement is finalised, including any rebates, credits and variations as part of the standard contractual process. Amortisation of oil and gas assets The amortisation of oil and gas assets are impacted by management’s estimates of reserves and future development costs. Refer to the significant accounting judgements, estimates and assumptions section on page 78 in relation to reserves. Future development cost estimates are costs necessary to develop an assets’ undeveloped 2P reserves. These costs are subject to changes in technology, regulation and other external factors. Significant accounting judgements, estimates and assumptions are also made in relation to the impairment of oil and gas assets and recognition of restoration assets, refer to Note 14 and Note 15 respectively. 14. Impairment Exploration and evaluation assets Oil and gas assets 2020 $’000 79,398 28,100 107,498 2019 $’000 - - - Recoverable amounts and resulting impairment write-downs recognised in the year ended 30 June 2020: Segment Recoverable amount method Impairment Write-downs $’000 Recoverable amount $’000 Exploration and evaluation assets VIC/RL 13-15 VIC/P44 PEL 92 Exploration Onshore Otway Total impairment of exploration and evaluation assets South-East Australia South-East Australia Cooper Basin South-East Australia FVLCD FVLCD FVLCD FVLCD Oil and gas assets Casino Henry Total impairment of oil and gas assets South-East Australia FVLCD Total impairment of exploration and evaluation and oil and gas assets 98,600 28,000 nil 20,982 94,500 41,700 29,100 7,836 762 79,398 28,100 28,100 107,498 94 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 14. Impairment continued Exploration and evaluation impairment VIC/RL 13-15 The FVLCD of VIC/RL 13-15 was determined based on expectations of the estimated future cash flows required to develop the Manta 2C resource and those estimated cash flows arising from use of the asset. A pre-tax discount rate of 10.6% has been applied, reflective of the risks specific to an asset in the exploration and evaluation phase. In addition, a portion of value is ascribed to the Manta deep prospective resource based on multiples and risking of discounted cash flows. Other relevant assumptions are outlined in the Significant Accounting Judgements, Estimates and Assumptions section that follows. The carrying value of VIC/RL 13-15 increased during the year due to increases in the associated BMG abandonment provision as outlined in Note 15. This increase along with decreases in long-term gas price assumptions have given rise to an impairment. Changes in key assumptions to which the recoverable amount is most sensitive would result in higher or lower carrying values as follows: Resultant impact on carrying value Long-term gas price: increase/(decrease) of $1/GJ Discount rate: decrease/(increase) of 1% Discount rate: decrease/(increase) in risking of Manta Deep of 5% Capital expenditure: decrease/(increase) of 10% 12-month delay to Manta gas project VIC/P44 Higher $’000 35,300 25,400 23,600 22,600 n/a Lower $’000 (35,700) (22,100) (23,600) (22,900) (9,000) The FVLCD of VIC/P44 was determined based on expectations of the estimated future cash flows required to develop the Annie 2C resource combined with undeveloped reserves in Casino Henry and from utilising the asset. A pre-tax discount rate of 10.8% has been applied, reflective of the risks specific to an asset in the exploration and evaluation phase. Other relevant assumptions are those outlined in the Significant Accounting Judgements, Estimates and Assumptions section that follows. The carrying value of VIC/P44 increased during the year due to recognition of the Annie gas discovery in accordance with the successful efforts method. Prior to this, the carrying value was comprised mainly of acquisition costs related to prospective resources in the permit from the acquisition of Santos’ Victorian portfolio of assets. Decreases in long- term gas price assumptions and preliminary estimates of costs to develop have given rise to an impairment. Changes in key assumptions to which the recoverable amount is most sensitive would result in higher or lower carrying values as follows: Resultant impact on carrying value 12-month delay to OP3D project Long-term gas price: increase/(decrease) of $1/GJ Discount rate: decrease/(increase) of 1% Capital expenditure: decrease/(increase) of 10% PEL 92 Exploration Higher $’000 n/a 10,600 4,100 5,300 Lower $’000 (11,100) (10,600) (3,700) (5,100) The carrying value of PEL 92 exploration was comprised of carry forward exploration costs in non-producing areas of the PEL 92 area of interest. The asset has been impaired to nil in line with the absence of budgeted or planned exploration activities in the exploration area of interest. Onshore Otway The impairment of exploration assets relates to a specific Onshore Otway area of interest that has been reduced to nil. Oil and gas asset impairment Casino Henry The FVLCD of Casino Henry was determined based on expectations of the estimated future cash flows required to develop undeveloped 2P reserves in the Henry field combined with the Annie 2C resource and from utilising the asset. A pre-tax discount rate of 8.6% has been applied, reflective of the time value of money and risks specific to the asset. Other relevant assumptions are those outlined in the Significant Accounting Judgements, Estimates and Assumptions section that follows. The impairment of Casino Henry has arisen due to a combination of factors: • price assumptions for uncontracted gas have been revised to reflect the lower, post-COVID-19 prices currently prevailing and anticipated for 2021, increasing thereafter • largely uncontracted gas production from 1 January 2021 onwards • an increase in oil and gas assets associated with upward revisions in abandonment provisions as outlined in Note 15 • an increase in the estimate of costs to develop undeveloped reserves based on pre-select phase cost estimates obtained during the year in respect of the Otway Phase 3 Development (OP3D) project • other cost increases 95 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 14. Impairment continued Changes in key assumptions to which the recoverable amount is most sensitive would result in higher or lower carrying values as follows: Resultant impact on carrying value Long-term gas price: increase/(decrease) of $1/GJ Discount rate: decrease/(increase) of 1% Capital expenditure: decrease/(increase) of 10% 12-month delay to OP3D project Sole Higher $’000 16,200 8,900 5,600 n/a Lower $’000 (16,300) (8,100) (5,700) 1,400 The Sole asset was tested for impairment as indicators of impairment existed, notably the delay experienced by APA Group (APA) in commissioning the Orbost Gas Processing Plant (OGPP). The delay is the result of foaming in absorber vessels of the Sulphur Recovery Unit of the OGPP, which has impaired gas processing capacity, preventing the plant from producing at nameplate capacity of 68 TJ/d. Additionally, on 20 August 2020, Cooper Energy and APA announced that they had entered into a Transition Agreement (TA) as referenced in Note 30. The recoverable amount for Sole was assessed on a VIU basis which exceeded the Cash Generating Unit (CGU)’s carrying value of $532.2 million and therefore no impairment has been recognised. VIU for Sole was determined based on the estimated cash flows arising from use of the asset on a 2P reserve basis and incorporating terms in the TA. These terms include the completion of Phase 2 Works at the OGPP in the December 2020 quarter in order for the plant to reach nameplate processing capacity levels of 68 TJ/d shortly after, and cost and revenue sharing between APA and Cooper Energy whilst under the terms of the TA. Until completion of the Phase 2 works, a processing rate of 40-45 TJ/d has been assumed, being the demonstrated capability of the OGPP to maintain stable supply. Sales gas processed during this time is assumed to be sold at spot gas prices less transport costs, with term Gas Sales Agreements (GSAs) assumed to commence in January 2021. The cost of the Phase 2 works has not been finalised, with current estimates being $15 million (Cooper Energy share $7.5 million). Whilst the Sole asset has not been impaired, its value remains sensitive to variables including, but not limited to: • the timing of and costs required to achieve nameplate processing capacity of 68 TJ/d • processing capacity levels attained both pre and post Phase 2 Works • spot prices realised for gas sold prior to term GSAs commencing Adverse outcomes in one or more of the variables may give rise to an impairment of the asset in future periods. Accounting Policy The carrying values of non-current assets, including, property, plant and equipment, capitalised exploration and evaluation assets and oil and gas assets are assessed for indicators of impairment biannually. Where indicators of impairment are present, an impairment test is performed. An impairment loss is recognised for the amount by which the asset or CGU’s carrying amount exceeds its recoverable amount. The recoverable amount of a non-current asset or CGU is the higher of value in use (VIU) and fair value less costs of disposal (FVLCD). For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows (CGUs). In assessing VIU, the estimated future cash flows are discounted to their present value using a pre-tax rate that reflects the risks specific to the asset. Where the recoverable amount is based on the FVLCD, a discounted cash flow model is also used and the inputs are consistent with level 3 on the fair value hierarchy. The estimated future cash flows are discounted to their present value using a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the asset that would be taken into account by an independent market participant. 96 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 14. Impairment continued Significant Accounting Judgements, Estimates and Assumptions Impairment of exploration and evaluation assets The future recoverability of capitalised exploration and evaluation expenditure is dependent on a number of factors, including whether the Group decides to exploit the related lease itself or, if not, whether it successfully recovers the related exploration and evaluation asset through sale. Management is required to make certain estimates and assumptions in applying this policy. Factors which could impact the future recoverability include the level of oil and gas resources, future technological changes which could impact the cost of extraction, future legal changes (including changes to environmental restoration obligations) and changes to commodity prices. These estimates and assumptions may change as new information becomes available. To the extent that capitalised exploration and evaluation expenditure is determined not to be recoverable in the future, this will reduce profits and net assets in the period in which this determination is made. In addition, exploration and evaluation expenditure is capitalised if activities in the area of interest have not yet reached a stage which permits a reasonable assessment of the existence or otherwise of economically recoverable oil and gas reserves or resources. To the extent that it is determined in the future that this capitalised expenditure should be written off, this will reduce profits and net assets in the period in which this determination is made. Impairment of exploration and evaluation assets and oil and gas assets The Group reviews the carrying amount of oil and gas assets at each reporting date starting with analysis of any indicators of impairment. Where indicators of impairment are present, the Group will test whether the CGU’s recoverable amount exceeds its carrying amount. Relevant items of working capital and property, plant and equipment are allocated to CGUs when testing for impairment. The estimated expected cash flows used in the discounted cash flow model are based on management’s best estimate of the future production of reserves and sales volumes, commodity prices, foreign exchange rates, development expenditure in order to access the reserves, and operating expenditure. The Group’s commodity prices and foreign exchange rates for impairment testing are based on management’s best estimates of future market prices, with reference to external brokers, market data and futures prices. The Group’s gas price assumptions are based on contract prices applied against contracted gas volumes. The Group’s view of future uncontracted, long-term gas prices has been revised to reflect the lower, post-COVID-19 prices currently prevailing and is based on market data available such as the ACCC Gas Inquiry, South-East Australia gas market supply and demand information, oil prices and foreign exchange rates. The Group’s future pricing assumptions in real terms are set out below: Reporting Period Key assumption FY2021 FY2022 Brent crude oil (US$/bbl) 35.00 – 50.00 50.00 – 60.00 FY2023 60.00 FY2024+ 60.00 30 June 2020 30 June 2019 Uncontracted gas ($/GJ) 6.00 - 8.00 8.00 – 11.00 Brent crude oil (US$/bbl) 67.50 67.50 67.50 67.50 Uncontracted gas ($/GJ) 9.00 – 12.00 The Group assumes foreign currency exchange rates of A$1/US$0.65 for FY21 and A$1/US$0.68 for subsequent periods. Discount rates applied in the net present value calculation of the VIU are derived from the weighted average cost of capital. The Group applied a range of pre-tax real discount rates between 8.6% and 10.8% (2019: 9.03%). In the event circumstances vary from the assumptions used in the impairment assessment, the recoverable amount of the Group’s assets or CGUs could change materially and result in further impairment losses. The key variables that impact on asset values are often interrelated and therefore, changes in individual variables rarely occur in isolation of other changes. Furthermore, management is able to respond to certain changes in variables and mitigate losses or maximise value depending on the prevailing conditions that exist at the time. Accordingly, while sensitivities have been provided for specific changes in key assumptions, the indirect impact that a change in one variable has on another is impractical to estimate, as is the potential for, and size of any further impairment write-downs or reversals in future reporting periods. 97 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 15. Provisions Current Liabilities Restoration provisions Employee provisions Non-Current Liabilities Employee provisions Restoration provisions Movement in carrying amount of the current restoration provision: Carrying amount at beginning of period Restoration expenditure incurred New provisions and changes in restoration assumptions (i) Transferred (to)/from non-current provisions Carrying amount at end of period Movement in carrying amount of the non-current restoration provision: Carrying amount at beginning of period New provisions and changes in restoration assumptions (i) Provision through asset acquisition Transferred from/(to) current provisions Increase through accretion Change in discount rate Carrying amount at end of period 2020 $’000 17,899 2,003 19,902 367 374,304 374,671 2020 $’000 9,989 (2,380) - 10,290 17,899 276,228 88,473 4,957 (10,290) 4,001 10,935 2019 $’000 9,989 1,142 11,131 561 276,228 276,789 2019 $’000 67,651 (10,112) 1,185 (48,735) 9,989 106,070 98,432 - 48,735 4,902 18,089 374,304 276,228 (i) New provisions recognised is in respect of restoration provisions arising from exploration permits (2019: Sole Horizontal Directional Drilling (HDD) and pipeline and exploration permits). Changes to restoration assumptions primarily represent changes to gross cost estimates for restoration work. In the current year, work on the BMG restoration project has progressed, resulting in the Group applying current regulatory requirements, decommissioning cost data acquired during the period, and taking account of the US dollar exchange rate across the portfolio. These updated estimates were taken into consideration when the Group reviewed the gross cost estimates for the other wells in the portfolio. In the current year, the timing of restoration has also changed for a number of non-operated assets. The abandonment and remediation work on BMG is expected to be completed in the 2023 calendar year subject to rig availability and regulatory approvals. The abandonment and remediation work on offshore wells and pipelines is estimated to be performed between 2025 to 2045. The discount rate used in the calculation of the provisions as at 30 June 2020 ranged from 0.24% to 1.72% (2019: 0.96% to 1.82%) reflecting a risk-free rate that aligns to the timing of restoration obligations. The reduction in the risk-free rate reflects the change in Australian government bond rates since the last assessment. 98 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 15. Provisions continued Accounting Policy Provisions are recognised when the Group has a legal or constructive obligation as a result of past transactions or other past events, it is probable that a future sacrifice of economic benefits will be required and a reliable estimate can be made of the amount of the obligation. Employee benefits Liabilities for wages and salaries, including non-monetary benefits and annual leave are recognised in respect of employees’ services up to the reporting date and are measured at the amount expected to be paid when the liabilities are settled. Expenses for non-accumulating sick leave are recognised when the leave is taken and are measured at the rates paid or payable. The provision for long service leave is recognised and measured as the present value of expected future payments to be made in respect of services provided by employees up to the reporting date using the projected unit credit method. Consideration is given to expected future wage and salary levels, experience of employee departures, and periods of service. Expected future payments are discounted using market yields at the reporting date based on high quality corporate bonds with terms of maturity and currencies that match, as closely as possible, the estimated future cash outflows. Employees’ accumulated long service leave is ascribed to individual employees at the rates payable as and when they become entitled to long service leave. A provision for bonus is recognised and measured based upon the current wage and salary level and forms part of the employee short term incentive plan. The basis for the bonus relating to Key Management Personnel is set out in the Remuneration Report. Restoration The Group records a restoration provision for the present value of its share of the estimated cost to restore its sites. The nature of restoration activities includes the obligations relating to the reclamation, waste site closure, plant closure, production facility removal and other costs associated with the restoration of the site. A restoration provision is recognised upon commencement of construction and then reviewed biannually at each reporting date. When the liability is recorded the carrying amount of the production or exploration asset is increased by the same amount and is depreciated over the remaining producing life of the asset. The movement is recorded as a restoration expense when there is no asset recorded. Over time, the liability is increased for the change in the present value based on a risk-free discount rate. The unwinding of the discount is recorded as an accretion charge within finance costs. Any changes in the estimate of the provision for restoration arising from changes in the gross cost estimate or changes in the discount rate of the restoration provision are recorded by adjusting the provision and the carrying amount of the production or exploration asset, to the extent that it is appropriate to recognise an asset under accounting standards, and then depreciated over the remaining producing life of the asset. Where it is not appropriate to recognise an asset, changes will go through profit or loss. Any change in assumptions is applied prospectively. These estimated costs are based on current technology available, State, Federal and International legislation and or industry practice. Significant Accounting Judgements, Estimates and Assumptions Provisions for restoration costs Decommissioning and restoration costs are a normal consequence of oil and gas extraction and the majority of this expenditure is incurred at the end of a field’s life. In determining an appropriate level of provision, assumptions are made on the expected future costs to be incurred, the timing of these expected future costs (largely dependent on the life of the field), and the estimated future level of inflation. The ultimate cost of decommissioning and restoration is uncertain and these ultimate costs can vary in response to many factors. These include the extent of restoration required due to changes to the relevant legal or regulatory requirements and the emergence of new restoration techniques or experience at other fields, including prevailing service costs. The expected timing of expenditure can also change, for example in response to changes in oil and gas reserves or to production rates. Changes to any of the estimates could result in significant changes to the amount of the provision recognised, which would in turn impact future financial results. 99 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 16. Leases The Group has adopted AASB 16 Leases from 1 July 2019. Refer to the New accounting standards and interpretations section for related transition disclosures. The Group as a lessee The Group has lease contracts for properties with lease terms of between 1-11 years and fixed monthly payments. The Group also has certain leases with lease terms of 12 months or less and low value leases. Right-of-use assets Reconciliation of carrying amounts at beginning and end of period: Carrying amount at beginning of period Transition – Right-of-use assets recognised 1 July 2019 Additions Depreciation Carrying amount at end of period Cost Accumulated depreciated Carrying amount at end of period Lease liabilities Reconciliation of carrying amounts at beginning and end of period: Carrying amount at beginning of period Transition - Lease liabilities recognised 1 July 2019 Additions Accretion of interest Payments Carrying amount at end of period Current Non-Current 2020 $’000 - 8,135 2,723 (1,120) 9,738 10,858 (1,120) 9,738 2020 $’000 - 9,378 4,624 634 (1,587) 13,049 1,045 12,004 Short-term and low-value lease asset exemptions For the year ending 30 June 2020, the following expense has been recognised in the Statement of Comprehensive Income for lease arrangements that have been classified as short-term leases or low-value assets Short-term leases Leases for low-value assets Total expense recognised 2020 $’000 - 18 18 The Group had total cash outflows for leases of $1.6 million in 2020, including leases for short-term leases and low-value assets. The future cash outflows relating to leases that have not yet commenced is disclosed in Note 26. 100 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 16. Leases continued Accounting Policy The Group recognises right-of-use assets and corresponding lease liabilities at the commencement date of the lease (the date the underlying asset is available for use). The right-of-use assets are initially measured at a value equal to the lease liability, adjusted for any initial direct costs incurred, and lease payments made at or before the commencement date less any lease incentives received. Subsequently, the right-of-use assets are measured at cost, less any accumulated depreciation and impairment losses, and adjusted for any remeasurement of lease liabilities. The property right-of-use assets are depreciated on a straight-line basis over the shorter of its estimated useful life and the lease term. Right-of-use assets are also allocated to Cash Generating Units (CGUs) when testing for impairment (refer to Note 14). Lease liabilities are excluded from the carrying amount of a CGU. At the commencement date of the lease, the Group recognises lease liabilities measured at the present value of lease payments to be made over the lease term. In calculating the present value of lease payments, the Group uses the incremental borrowing rate at the lease commencement date if the interest rate implicit in the lease is not readily determinable. Subsequent to initial measurement, the amount of lease liabilities is increased to reflect the accretion of interest and reduced for the lease payments made. The carrying amount of lease liabilities is remeasured if there is a modification, a change in the lease term, a change in the fixed lease payments or a change in the assessment to purchase the underlying asset. The Group applies the short-term lease recognition exemption to its short-term leases (those leases that have a lease term of 12 months or less from the commencement date and do not contain a purchase option). It also applies the lease of low-value assets recognition exemption to leases of office equipment that are considered of low value (below $10,000). Lease payments on short-term leases and leases of low-value assets are recognised as expense on a straight-line basis over the lease term. Significant Accounting Judgements, Estimates and Assumptions Lease term of contracts with renewal options The Group determines the lease term as the non-cancellable term of the lease, together with any periods covered by an option to extend the lease if the option is reasonably certain to be exercised. The Group has the option, under some of its leases to lease the assets for additional terms of three to five years. The Group applies judgement in evaluating whether it is reasonably certain to exercise the option to renew. The Group continues to reassess the lease over its term to determine if there is a significant event or change in circumstances that would impact the renewal decision. The Group has included the renewal period as part of the lease term for its property leases. 17. Government grants Reconciliation of government grants at beginning and end of period: At beginning of period Grant received during the year Allocated to exploration and evaluation assets At end of period Accounting Policy 2020 $’000 430 - (430) - 2019 $’000 2,067 - (1,637) 430 Grants from the government are recognised at their fair value where there is a reasonable assurance that the grant will be received and the Group will comply with all attached conditions. Government grants received in relation to exploration and evaluation assets, oil and gas assets or property, plant and equipment are recognised as a reduction in the carrying value of the asset as expenditure is incurred. 101 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 Funding and Risk Management 18. Interest bearing loans and borrowings Current bank debt Non-current bank debt Net of capitalised transaction costs of $nil (2019: $4.5 million). 2020 $’000 26,000 203,438 2019 $’000 - 213,680 In August 2017, Cooper Energy negotiated a $250.0 million senior secured Reserve Based Lending Facility, principally to fund the Sole Gas Project, and a senior secured $15.0 million working capital facility. Cooper Energy is in compliance with all covenants at 30 June 2020. A summary of the Group’s secured facilities is included below. Facility Currency Limit1 Reserve Based Lending Facility Australian dollars $250.0 million (2019: $250.0 million) Utilised amount $229.4 million (2019: $218.2 million) Accounting balance $229.4 million (2019: $213.7 million) Effective interest rate 6.01% floating Maturity² Facility Currency Limit 2021 – 2024 Working Capital Facility Australian Dollars $15.0 million (2019: $15 million) Utilised amount3 $1.5 million (2019: $1.7 million) Accounting balance Nil (2019: Nil) Effective interest rate Nil Maturity 28 September 2022 1. As at 30 June 2020, $233.0 million of the facility limit of $250.0 million is currently available. 2. Repayment profile based on facility utilisation and reserves profile following completion of the Sole Gas Project 3. As at 30 June 2020, no amounts have been drawn down, but $1.5 million has been utilised by way of bank guarantees. Accounting Policy Borrowings are recognised initially at fair value net of directly attributable transaction costs. Subsequent to initial recognition, borrowings are stated at amortised cost, with any difference between cost and redemption value being recognised in profit or loss over the period of the borrowings on an effective interest basis. Transaction costs are capitalised initially and included in the effective interest rate calculation and unwound over the expected term of the facility. Borrowings are classified as current liabilities unless the Group has an unconditional right to defer the settlement of the liability for at least 12 months after the end of the reporting period. Interest expense is recognised as interest accrues using the effective interest rate and if not paid at balance date, is reflected in the balance sheet as a payable. 102 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 19. Net finance costs Finance Income Interest income Finance Costs Accretion of restoration provision Accretion of success fee liability Finance costs associated with lease liabilities Interest expense Capitalised interest Total finance costs Net finance costs Accounting Policy 2020 $’000 2019 $’000 1,728 3,398 (4,001) (4,902) (37) (634) (70) - (12,580) (11,015) 9,665 (7,587) (5,859) 11,015 (4,972) (1,574) Interest earned is recognised in the Consolidated Statement of Comprehensive Income as finance income and is recognised as interest accrues using the effective interest rate. This is the rate that exactly discounts estimated future cash receipts through the expected life of the financial instrument to the net carrying amount of the financial asset. Interest expense is capitalised to the cost of a qualifying asset during the development phase. 20. Contributed equity and reserves Capital Management For the purpose of the Group’s capital management, capital includes issued capital and all other equity reserves attributable to the equity holders of the parent entity. The primary objective of the Group’s capital management is to maintain an appropriate capital profile to support its business activities and to maximise shareholder value. At 30 June 2020, the Group has utilised $229.4 million of its Reserve Based Lending Facility. The Group manages its capital structure and makes adjustments in light of economic conditions and the requirements of the financial covenants. To maintain or adjust the capital structure, the Group may adjust its dividend policy, return capital to shareholders, issue new shares or draw on debt. No changes were made in the objectives, policies or processes during the current and prior period. Share capital Ordinary shares issued and fully paid Movement in ordinary shares on issue At 1 July Issuance of shares for Performance Rights and Share Appreciation Rights Issuance of shares to contractors At 30 June Accounting Policy 2020 $’000 2019 $’000 475,862 474,397 2020 2019 Thousands $’000 Thousands $’000 1,621,551 474,397 1,601,079 471,837 5,096 - 1,465 - 19,682 790 2,217 343 1,626,647 475,862 1,621,551 474,397 Issued and paid up capital is recognised as the fair value of the consideration received by the Group. The shares issued do not have a par value and there is no limit on the authorised share capital of the Group. Fully paid ordinary shares carry one vote per share, which entitles the holder to participate in the proceeds on winding up of the company in proportion to the number of, and amounts paid on, the shares held. Any transaction costs arising on the issue of ordinary shares that would not have been incurred had ordinary shares not been issued are recognised directly in equity as a reduction of the share proceeds received. The Group may issue shares to contractors at its discretion in exchange for services rendered. The cost of these issued shares is measured by reference to the fair value at the date at which they are granted. 103 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 20. Contributed equity and reserves continued Reserves Consolidation reserve $’000 (541) - - - (541) - - - Share based payment reserve $’000 9,586 - (2,217) 3,422 10,791 - (1,465) 3,504 (541) 12,830 Consolidated At 1 July 2018 Other comprehensive expenditure Transferred to issued capital Share-based payments At 30 June 2019 Other comprehensive income/ (expenditure) Transferred to issued capital Share-based payments At 30 June 2020 Nature and purpose of reserves Consolidation reserve Option premium reserve $’000 Cash flow hedge reserve $’000 Equity instrument reserve $’000 25 - - - 25 - - - 25 310 (894) - - (584) 584 - - - 545 (989) - - (444) (690) - - Total $’000 9,925 (1,883) (2,217) 3,422 9,247 (106) (1,465) 3,504 (1,134) 11,180 The reserve comprises the premium paid on acquisition of minority shareholdings in a controlled entity. Share based payment reserve This reserve is used to record the value of equity benefits provided to employees, contractors and Executive Directors as part of their remuneration. Option premium reserve This reserve is used to accumulate amounts received from the issue of options. The reserve can be used to pay dividends or issue bonus shares. Cash flow hedge reserve This reserve is used to capture the effective portion of the mark to market movement of instruments designed in a hedge relationship. Equity instruments reserve This reserve is used to capture the fair value movement in the value of equity instruments designated at fair value through Other Comprehensive Income. Items in this reserve are never recycled through profit or loss. 2020 $’000 (49,931) (86,029) (135,960) 2019 $’000 (37,880) (12,051) (49,931) Accumulated Losses Movement in accumulated losses: Balance at 1 July Net loss for the year Balance at 30 June 104 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 21. Financial risk management The Group’s principal financial instruments comprise cash and short-term deposits (Note 5), receivables (Note 6), payables (Note 9), borrowings (Note 18) and other financial assets and liabilities as disclosed in the below table. Other financial assets – Non-Current Equity instruments¹ Escrow proceeds receivable 2020 $’000 564 20,968 21,532 1. The equity instruments consist of two investments and the Group has not received dividends during the financial year. Other financial liabilities – Current Derivative financial instruments designated in a hedge relationship Other financial liabilities – Non-Current Success fee financial liability Movement in carrying amount of the success fee financial liability: Carrying amount at 1 July Accretion of success fee liability Fair value adjustment Carrying amount at 30 June Fair value hierarchy - - 3,642 3,642 3,482 37 123 3,642 2019 $’000 1,252 20,488 21,740 1,758 1,758 3,482 3,482 3,054 70 358 3,482 Fair value is the price that would be received to sell an asset or the price that would be paid to transfer a liability in an orderly transaction between market participants at the measurement date. All financial instruments for which fair value is recognised or disclosed are categorised within the fair value hierarchy, described as follows, and based on the lowest level input that is significant to the fair value measurement as a whole: Level 1 Quoted market prices in an active market (that are unadjusted) for identical assets or liabilities Level 2 Valuation techniques for which the lowest level input that is significant to the fair value measurement is directly or indirectly observable Level 3 Valuation techniques for which the lowest level input that is significant to the fair value measurement is unobservable For financial instruments that are recognised at fair value on a recurring basis, the Group determines whether transfers have occurred between levels in the hierarchy by re-assessing categorisation (based on the lowest level input that is significant to the fair value measurement as a whole) at the end of each reporting period. 105 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 21. Financial risk management continued Set out below are the carrying amounts and fair values of financial instruments held by the Group: Financial assets Trade and other receivables Equity instruments Escrow proceeds receivable Financial liabilities Trade and other payables Success fee financial liability Derivative financial instruments designated in a hedge relationship Interest bearing loans and borrowings Carrying amount Fair value Level 2020 $’000 2019 $’000 2020 $’000 2019 $’000 2 1 2 2 3 2 2 19,996 21,169 19,996 564 1,252 564 20,968 20,488 20,968 21,183 3,642 44,533 3,482 21,183 3,642 21,169 1,252 20,488 44,533 3,482 - 1,758 - 1,758 229,438 213,680 230,705 215,566 The following summarises the significant methods and assumptions used in estimating the fair values of financial instruments: Equity instruments Equity instruments are not held for trading and measured at fair value through other comprehensive income based on an irrevocable election made at inception on an instrument basis and are initially recognised at fair value plus any directly attributable transaction costs. After initial recognition, investments are remeasured to fair value determined by reference to their quoted market price on a prescribed equity stock exchange at the reporting date, and hence is a Level 1 fair value measurement. Changes in the fair value of equity investments are recognised as a separate component of equity and not recycled to profit and loss at any stage. Any dividends received are reflected in profit or loss. Escrow proceeds receivable During the 2018 financial year, the Group completed the sale of Orbost Gas Processing Plant to APA Group. A portion of proceeds from the sale is held in escrow, to be released upon certain conditions being satisfied. Amounts held in escrow are measured at amortised cost in the Consolidated Statement of Financial Position. Derivative financial instruments designated in a hedge relationship The derivative financial instruments relate to the Group’s hedging activities to hedge against cash flow risks from movements in interest rates (and oil price in the prior year), for which hedge accounting has been applied. The derivative financial instruments are measured at fair value through other comprehensive income and released to profit and loss in line with the hedged item and the fair value is obtained from third party valuation reports. Success fee financial liability The success fee liability is the fair value of the Group’s liability to pay a $5.0 million success fee upon the commencement of commercial production of hydrocarbons on the Group’s VIC/RL 13-15 assets acquired on 7 May 2014. The significant unobservable (level 3) valuation inputs for the success fee financial liability includes: a probability of 33% that no payment is made and a probability of 67% the payment is made in 2024. The discount rate used in the calculation of the liability as at 30 June 2020 equalled 0.49% (June 2019: 1.02%). The financial liability is measured at fair value through profit and loss and valued using a discounted cash flow model and the value is sensitive to changes in discount rate and probability of payment. Significant changes in any of the significant unobservable inputs would result in significantly higher or lower fair value measurement. Risk Management The Group manages its exposure to key financial risks in accordance with its risk management policy with the objective to ensure that the financial risks inherent in oil and gas exploration activities are identified and then managed or kept as low as reasonably practicable. The Group has a separate Risk and Sustainability Committee. The main financial risks that arise in the normal course of business for the Group’s financial instruments are foreign currency risk, commodity price risk, share price risk, credit risk, liquidity risk and interest rate risk. The Group uses different methods to measure and manage different types of risks to which it is exposed. These include monitoring exposure to foreign exchange risk and assessments of market forecast for interest rates, foreign exchange and commodity prices. Liquidity risk is monitored through the development of future rolling cash flow forecasts. The Board’s policy is that no speculative trading in financial instruments be undertaken. The primary responsibility for the identification and control of financial risks rests with the Managing Director and the Chief Financial Officer, under the authority of the Board. The Board is apprised of these and other risks at Board meetings and agrees any policies that may be implemented to manage any of the risks identified below. 106 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 21. Financial risk management continued Market risk Market risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate because of changes in market prices. Market risk comprises four types of risk: foreign currency risk, commodity price risk, interest rate risk and share price risk. Financial instruments affected by market risk include deposits, trade receivables, trade payables, accrued liabilities and borrowings. The sensitivity analyses in the following sections relate to the position as at 30 June 2020 and 30 June 2019. The sensitivity analyses are intended to illustrate the sensitivity to changes in market variables on the Group’s financial instruments and show the impact on profit or loss and shareholders’ equity, where applicable. When calculating the sensitivity analyses, it is assumed that the sensitivity of the relevant profit before tax item and/or equity is the effect of the assumed changes in respective market risks, with all other variables held constant. This is based on the financial assets and financial liabilities held at 30 June 2020 and 30 June 2019. a) Foreign currency risk The Group has transactional currency exposure arising from oil sales which are denominated in United States dollars, whilst almost all its costs are denominated in Australian dollars. The majority of costs are denominated in Australian dollars, however there are some costs incurred in Great British pounds and United States dollars. Transaction exposures, where possible, are netted off across the Group to reduce volatility and provide a natural hedge. The Group may from time to time have cash denominated in United States dollars. Currently the Group has no foreign exchange hedge programmes in place. The Group manages the purchase of foreign currency to meet expenditure requirements, which cannot be netted off against US dollar receivables. The financial instruments which are denominated in US dollars are as follows: Financial assets Cash Trade and other receivables b) Commodity price risk 2020 $’000 13,830 2,176 2019 $’000 3,980 5,591 The Group uses oil price options to manage some of its transaction exposures. Options entered into have not been designated as cash flow hedges and are entered into for periods consistent with oil price exposure of the underlying transactions, generally from one to 12 months. Commodity price risk arises from the sale of oil denominated in US dollars. The Group has provisional sales at 30 June 2020 of $2.2 million (2019: $5.6 million). c) Interest rate risk The Group has borrowings of $229.4 million at 30 June 2020 (2019: $213.7 million). Interest on borrowings are at variable rates (refer to Note 18) and are capitalised while the project is in development. The Group has fixed rate term deposits that are not impacted by changes in the interest rate at balance date. d) Share price risk Share price risk arises from the movement of share prices on a prescribed stock exchange. The Group has equity instruments measured at fair value through other comprehensive income the fair value of which fluctuates as a result of movement in the share price. The following table summarises the sensitivity of financial instruments held at the year end, to the market risks above, with all other variables held constant. If the Australian dollar were 10% higher at the balance date If the Australian dollar were 10% lower at the balance date If the Brent Average price were 10% higher at the balance date If the Brent Average price were 10% lower at the balance date If the interest rates were 10% higher at the balance date If the interest rates were 10% lower at the balance date If the share price were 10% higher at the balance date If the share price were 10% lower at the balance date 2020 $’000 2019 $’000 Impact on after tax profit (1,455) 1,778 397 (397) (2,294) 2,294 (870) 1,063 656 (656) - - Impact on reserve 56 (56) 125 (125) 107 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 21. Financial risk management continued Credit risk Credit risk arises from the financial assets of the Group which comprise cash and cash equivalents and trade and other receivables including hedge settlement receivables, escrow proceeds receivable (disclosed as other financial assets), and certain prepayments. The Group’s exposure to credit risk arises from potential default of the counter party, with a maximum exposure equal to the carrying amount of these instruments. The Group trades only with recognised creditworthy third parties and has had no exposure to expected credit losses. The Group has a concentration of credit risk with trade receivables due from a small number of entities which have traded with the Group since 2003. Trade receivables are settled on 30 to 90 day terms. There are no amounts provided for based on lifetime expected credit loss from trading customers. The Group has some exposure to credit loss from other receivables and an amount of $2.4 million calculated on lifetime expected credit loss has been recognised in respect of a credit-impaired receivable. Cash and cash equivalents, term deposits and escrow proceeds receivable are held at three financial institutions that have a Standard & Poor’s A credit rating or better. Liquidity risk Liquidity risk is the risk that the Group will not be able to meet its financial obligations as they fall due. The liquidity position of the Group is managed to ensure sufficient liquid funds are available to meet all financial commitments in a timely and cost-effective manner. The Managing Director and Chief Financial Officer review the liquidity position on a regular basis including cash flow forecasts to determine the forecast liquidity position and maintain appropriate liquidity levels. Any fluctuation of the interest rate either up or down will have no impact on the principal amount of the cash on term deposit at the banks. The Group does not invest in financial instruments that are traded on any secondary market. The table below summarises the maturity profile of the Group’s financial liabilities based on contractual undiscounted payments: At 30 June 2020 Trade and other payables Lease liabilities Interest bearing loans and borrowings Success fee financial liability Less than 3 months $’000 3 to 12 months $’000 1 to 5 years $’000 Greater than 5 years $’000 21,183 258 2,530 - - 786 - 6,887 35,192 218,017 - 5,000 - 5,118 - - Total $’000 21,183 13,049 255,739 5,000 23,971 35,978 229,904 5,118 294,971 At 30 June 2019 Trade and other payables¹ 41,644 Interest bearing loans and borrowings Success fee financial liability Derivative financial liabilities designated in a hedge relationship - - - - 9,490 - 1,758 - 235,262 5,000 - - 15,763 - - 41,644 260,514 5,000 1,758 1. Excludes deferred lease incentive 41,644 11,248 240,262 15,763 308,916 108 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 22. Hedge accounting The Group uses interest rate swaps to manage its exposure to fluctuations in interest rates. The swaps are designated as cash flow hedges and are entered into for a period consistent with the exposure of the underlying transactions. Cash flow hedges – interest rate swaps Interest rate swaps measured at fair value through other comprehensive income are designated as hedging instruments in cash flow hedges of forecast interest payments in respect of the Group’s reserve base lending facility. Carrying amount $nil (2019: $1.8 million liability) Notional value Hedge cover Maturity date Average hedged rate $nil (2019: $161.7 million) Nil (2019: 74%) N/A N/A The fair value of the swaps varies based on changes in forward rates. Fair value of interest rate swaps 30 June 2020 30 June 2019 Assets $’000 - Liabilities $’000 Assets $’000 Liabilities $’000 - - 1,758 The terms of the interest rate swaps match the terms of the expected highly probable forecast interest payments. The cash flow hedges of the expected future interest payments were assessed to be highly effective and a net unrealised gain of $2.1 million (2019: $1.3 million net unrealised loss) and a tax expense of $0.4 million (2019: tax benefit of $0.4 million) relating to the hedging instrument are included in OCI. $1.2 million has been reclassified to the profit and loss in the current period. Accounting Policy Derivatives are initially recognised at their fair value when the Group becomes a party to the contract. Derivative financial instruments measured at fair value through profit and loss may be designated as hedging instruments in a hedge relationship. Cash flow hedges The Group uses interest rate swaps as hedges of its exposure to interest rate risk in forecast transactions. Amounts recognised as other comprehensive income are transferred to profit or loss when the hedged transaction affects profit or loss – when the sale occurs or when interest is paid. Hedge effectiveness is determined at the inception of the hedge relationship and through periodic prospective effectiveness assessments to ensure an economic relationship exists between the hedged item and a hedging instrument. The Group enters into hedging relationships where the critical terms of the hedging instrument match exactly with the terms of the hedged item and so a qualitative assessment of effectiveness is performed. If changes in circumstances affect the terms of the hedged item such that the critical terms no longer match exactly with the critical terms of the hedging instrument, the Group uses the hypothetical derivative method to assess effectiveness. The effective portion of the gain or loss on the hedging instrument is recognised in other comprehensive income in the cash flow hedge reserve while any ineffective portion is recognised immediately in the statement of profit or loss. If the hedging instrument expires or is sold, terminated or exercised without replacement or rollover, or when the hedge no longer meets the criteria for hedge accounting, any cumulative gain or loss previously recognised in other comprehensive income remains separately in equity until the forecast transaction occurs. 109 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 Group Structure 23. Interests in joint arrangements The Group has the following interests in joint arrangements involved in the exploration and/or production of oil and gas in Australia: Ownership Interest 2020 2019 Joint Arrangements in Australia in which Cooper Energy Limited is the operator/manager VIC/L24 & 30 Gas exploration and production 50% 50% Joint Arrangements in Australia in which Cooper Energy Limited is not the operator/manager PEL 90K PEL 93¹ PRL 237 Oil and gas exploration Oil and gas exploration and production Oil and gas exploration - 30% 20% 25% 30% 20% PRL 207-209 (Formerly PEL 100) Oil and gas exploration 19.165% 19.165% PRL 183-190 (Formerly PEL 110) Oil and gas exploration PEL 494 PEP 150 PEP 168 PEP 171 PRL 32 Oil and gas exploration Oil and gas exploration Oil and gas exploration Oil and gas exploration Oil and gas exploration PRL 85-104¹ (Formerly PEL 92) Oil and gas exploration and production 1. Includes associated PPLs. Accounting Policy 20% 30% 50% 50% 75% 30% 25% 20% 30% 50% 50% 75% 30% 25% The Group has interests in arrangements that are controlled jointly. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control. A joint arrangement is either a joint operation or a joint venture. The Group has several joint arrangements which are classified as joint operations. A joint operation is a joint arrangement whereby the parties that have joint control of the arrangement, have rights to the assets, and obligations for the liabilities, relating to the arrangement. In relation to its interests in joint operations, the Group recognises its: • Assets, including its share of any assets held jointly • Liabilities, including its share of any liabilities incurred jointly • Revenue from the sale of its share of the output arising from the joint operation • Expenses, including its share of any expenses incurred jointly Significant Accounting Judgements, Estimates and Assumptions Joint arrangements Judgement is required to determine when the Group has joint control over an arrangement, which requires an assessment of the relevant activities and when the decisions in relation to those activities require unanimous consent. The Group has determined that the relevant activities for its joint arrangements are those relating to the operating and capital decisions of the arrangement, such as approval of the capital expenditure program for each year and appointing, remunerating and terminating the key management personnel or service providers of the joint arrangement. Where joint control does not exist, the relationship is not accounted for as a joint arrangement. The considerations made in determining joint control are similar to those necessary to determine control over subsidiaries. Judgement is also required to classify a joint arrangement. Classifying the arrangement requires the Group to assess their rights and obligations arising from the arrangement. Specifically, the Group considers: • The structure of the joint arrangement – whether it is structured through a separate vehicle; • When the arrangement is structured through a separate vehicle, the Group also considers the rights and obligations arising from: The legal form of the separate vehicle; the terms of the contractual arrangement and; other facts and circumstances (when relevant). This assessment often requires significant judgement, and a different conclusion on joint control and also whether the arrangement is a joint operation or a joint venture, may materially impact the accounting. 110 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 24. Investments in controlled entities (a) Schedule of controlled entities The Group’s consolidated financial statements include the financial statements of Cooper Energy Limited and the subsidiaries listed in the following table. Name CE Tunisia Bargou Ltd CE Hammamet Ltd CE Nabeul Ltd Somerton Energy Limited Essential Petroleum Exploration Pty Ltd Cooper Energy (Australia) Pty Ltd Cooper Energy (PBF) Pty Ltd Cooper Energy (PB Pipelines) Pty Ltd Cooper Energy (CH) Pty Ltd Cooper Energy (TC) Pty Ltd Cooper Energy (MF) Pty Ltd Cooper Energy (MGP) Pty Ltd Cooper Energy (IC) Pty Ltd Cooper Energy (HC) Pty Ltd Cooper Energy (EA) Pty Ltd Cooper Energy (Sole) Pty Ltd Cooper Energy (VO) Pty Ltd Cooper Energy (Marketing) Pty Ltd Cooper Energy (BMG) Pty Ltd Cooper Energy (CB) Pty Ltd Cooper Energy (Finance) Pty Ltd Country of incorporation British Virgin Islands British Virgin Islands British Virgin Islands Australia Australia Australia Australia Australia Australia Australia Australia Australia Australia Australia Australia Australia Australia Australia Australia Australia Australia Note (a) (a) (a) (a) (a) (a) (a) (a) (a) (a) (a) (a) (a) (a) (a) Ownership interest 2020 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 2019 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% - - - The parties that comprise the Closed Group are denoted by (a). (b) Deed of Cross Guarantee Pursuant to ASIC Corporations (Wholly-owned Companies) Instrument 2016/785 dated 29 September 2016, relief has been granted to these controlled entities of Cooper Energy Limited from the Corporations Act 2001 for preparation, audit and lodgement of financial reports, and directors’ reports. As a condition of the Class Order, Cooper Energy Limited, and the controlled entities subject to the Class Order, entered into a Deed of Cross Guarantee. The effect of the deed is that Cooper Energy Limited has guaranteed to pay any deficiency in the event of the winding up of any member of the Closed Group, and each member of the Closed Group has given a guarantee to pay any deficiency, in the event that Cooper Energy Limited or any other member of the Closed Group is wound up. CE Tunisia Bargou Ltd, CE Hammamet Ltd, CE Nabeul Ltd, Cooper Energy (BMG) Pty Ltd, Cooper Energy (CB) Pty Ltd and Cooper Energy (Finance) Pty Ltd were inactive during the current and prior year, therefore the Financial Statements of the consolidated entity also represent the closed group results. (c) Asset acquisition On 1 May 2018, the Casino Henry Joint Venture participants entered into an agreement to acquire the BHP’s 90% interest in the Athena Gas Plant from the Minerva Joint Venture on cessation of current operations processing gas from the Minerva gas field. This transaction completed on 4 December 2019 and is when control passed. 111 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 24. Investments in controlled entities continued The table below shows the assets acquired as part of the transaction. Consideration transferred Inventory Property, plant and equipment Restoration provision Net assets acquired Accounting Policy 2020 $’000 4,113 396 8,674 (4,957) 4,113 Business combinations are accounted for using the acquisition method. The consideration for an acquisition is measured as the aggregate of the consideration transferred, measured at acquisition date fair value and the amount of any non-controlling interest in the acquiree. For each business combination, the Group elects whether it measures the non-controlling interest in the acquiree at fair value or at the proportionate share of the acquiree’s identifiable net assets. Acquisition costs incurred are expensed and included in administrative expenses. When the Group acquires a business, it assesses the financial assets and liabilities acquired for appropriate classification and designation per AASB 9 Financial Instruments (AASB 9) in accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date. If the business combination is achieved in stages, the acquisition date fair value of the acquirers previously held equity interest in the acquiree is remeasured to fair value at the acquisition date through profit or loss. Any contingent consideration to be transferred by the acquirer will be recognised at fair value at the acquisition date. Subsequent changes to the fair value of the contingent consideration that is deemed to be an asset or liability will be recognised in accordance with AASB 9 and measured at fair value through profit and loss. If the contingent consideration is classified as equity it will not be remeasured. Subsequent settlement is accounted for within equity. In instances where the contingent consideration does not fall within the scope of AASB 9, it is measured in accordance with the appropriate AASB. An asset or group of assets that do not meet the definition of a business are accounted for as asset acquisitions. Under this method, assets are initially recognised at cost based on their relative fair value at the date of acquisition. Under this method transaction costs are capitalised to the asset and not expensed. 25. Parent entity information Information relating to the parent entity, Cooper Energy Limited Current Assets Total Assets Current Liabilities Total Liabilities Issued capital Accumulated loss Option premium reserve Share based payment reserve Total shareholders’ equity (Loss)/Profit of the parent entity Total comprehensive (loss)/gain of the parent entity 112 2020 $’000 114,686 638,845 14,891 192,562 475,862 (42,794) 25 12,830 445,923 (39,302) (39,302) 2019 $’000 179,179 597,200 22,683 120,522 474,397 (8,535) 25 10,791 476,678 1,250 1,250 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 Other Information 26. Commitments for expenditure The Group has the following commitments for expenditure not provided for in the financial statements and payable. Due within 1 year Due within 1-5 years Due later than 5 years Total Exploration capital Leases 2020 $’000 32,300 68,944 - 2019 $’000 20,722 33,544 - 101,244 54,266 2020¹ $’000 24,273 242,729 112,398 379,400 2019² $’000 1,584 6,866 896 9,346 1. Commitments relating to leases that have not yet commenced 2. Relates to operating lease commitments under non-cancellable office lease. Refer to the transition disclosures within the new accounting standards and interpretations section for reconciliation of lease commitments disclosed to the lease liability recognised on transition to AASB 16 Leases. From time to time through the ordinary course of business, Cooper Energy enters into contractual arrangements that may give rise to negotiated outcomes. As at 30 June 2020 the Parent entity has bank guarantees for $1.5 million (2019: $1.7 million). These guarantees are in relation to performance bonds on exploration permits and guarantees on office leases. Accounting Policy The determination of whether an arrangement is or contains a lease is based on the substance of the arrangement and requires an assessment of whether the fulfilment of the arrangement is dependent on the use of a specific asset or assets and the arrangement conveys a right to use the asset. Operating lease payments are recognised as an expense in the Consolidated Statement of Comprehensive Income on a straight-line basis over the lease term. The Group has entered into commercial property leases. The Group has determined that is does not obtain any of the significant risks and rewards of ownership of these properties and has thus classified the leases as operating leases. This accounting policy was only applicable for the 2019 year. 27. Share based payments At the 2018 AGM, shareholders of Cooper Energy approved the plan referred to as the Equity Incentive Plan (EIP). Performance rights and share appreciation rights were issued for no consideration under the EIP. These rights issued will vest as shares in the parent entity subject to performance hurdles being met. A performance right is the right to acquire one fully paid share in the Company provided a specified hurdle is met and share appreciation rights are rights to acquire shares in the Company to the value of the difference in the Company share price between the grant date and vesting date. Testing of the performance rights and share appreciation rights will occur at the end of the three year performance period. Rights granted prior to the 2020 financial year may be retested once 12 months after the original three year test date. At the end of the three year measurement period, those rights that were tested and achieved will vest. The vesting test is determined from the absolute total shareholder return of Cooper Energy’s share price ranked against the absolute total shareholder returns of 12 peer companies listed on the Australian Securities Exchange. If Cooper Energy is ranked lower than the 50th percentile no rights will vest. If Cooper Energy is ranked in the 50th percentile 30% of the eligible rights will vest. If Cooper Energy is ranked greater than the 50th percentile but less than the 90th percentile the amount of eligible rights vested will be based on a pro rata calculation. If Cooper Energy is ranked in in the 90th percentile or higher 100% of the eligible rights will vest. Performance rights are also granted as part of deferred STIP and testing of these rights will occur at the end of a 12 month performance period. Rights granted will vest if the employee remains employed by the Company at the end of the performance period. There are no participating rights or entitlements inherent in the rights and holders will not be entitled to participate in new issues of capital offered to shareholders during the period of the rights. All rights are settled by physical delivery of shares. 113 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 27. Share based payments continued Information with respect to the number of performance rights and share appreciation rights granted to employees is as follows: Number of share appreciation rights (SARs) granted Number of performance rights granted Average share price at commencement date of grant Average contractual life of rights at grant date in years Remaining life of rights in years Date Granted 8 December 2017 12 December 2018 12 December 20181,2 15,898,978 13,312,848 - 11 December 2019 14,871,802 11 December 20192 - 1. Granted in December 2018 and exercised in December 2019 2. Relates to deferred STIP performance rights granted 6,330,443 4,888,166 697,284 4,257,209 769,605 $0.310 $0.435 $0.435 $0.575 $0.575 3 3 1 3 1 0.5 1.5 - 2.5 0.5 The number of performance rights and share appreciation rights held by employees is as follows: Balance at beginning of year - granted - vested Number of Share Appreciation Rights Number of Performance Rights1 2020 38,457,469 14,871,802 2019 46,017,694 13,312,848 2020 15,464,897 5,026,814 2019 17,846,179 5,585,450 (5,049,246) (19,269,412) (2,613,107) (7,296,874) - expired and not exercised - forfeited following employee termination - - - - (1,603,661) (15,975) (51,439) (618,419) Balance at end of year Achieved at end of year 48,280,025 38,457,469 17,862,629 15,464,897 - - - - 1. Includes deferred STIP issued as performance rights The fair value of services received in return for the performance rights granted are measured by reference to the fair value of performance rights granted. The estimate of the fair value of the services received is measured based on the Black-Scholes methodology to produce a Monte-Carlo simulation model that allows for the incorporation of market-based performance hurdles that must be met before the shares vest to the holder. Share Appreciation Rights fair value assumptions Fair value at measurement date Share price Risk free interest rate Expected volatility Dividend yield Performance Rights fair value assumptions Fair value at measurement date Share price Risk free interest rate Expected volatility Dividend yield 8 December 2017 12 December 2018 11 December 2019 12.4 cents 29.5 cents 1.94% 56% 0% 14.5 cents 43.5 cents 1.95% 49% 0% 15.8 cents 57.5 cents 0.68% 40% 0% 8 December 2017 12 December 2018 11 December 2019 22.4 cents 29.5 cents 1.94% 56% 0% 30.0 cents 43.5 cents 1.95% 49% 0% 37.7 cents 57.5 cents 0.68% 40% 0% 114 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 27. Share based payments continued Accounting Policy The Group provides benefits to employees of the Group in the form of share-based payment transactions, whereby employees render services in exchange for rights over shares (“equity-settled transactions”). The cost of these equity-settled transactions with employees is measured by reference to the fair value at the date at which they are granted and are recorded as an expense, with a corresponding increase in reserves, on a straight-line basis over the vesting period of the related instrument. The fair value is determined using the Black-Scholes methodology to produce a Monte-Carlo simulation model that takes into account the exercise price, the vesting period, the vesting and performance criteria, the impact of dilution, the non-tradable nature of the performance right or share appreciation right, the share price at grant date, the expected price volatility of the underlying share, the expected dividend yield and the risk-free interest rate for the term of the vesting period. The fair value of the performance rights and share appreciation rights granted excludes the impact of any non-market vesting conditions (for example, profitability and sales growth targets). The volatility assumption is based on the actual volatility of Cooper Energy’s daily closing share price over the three-year period to the valuation date. The cost of equity-settled transactions is recognised, together with a corresponding increase in equity, over the period in which the performance and/or service conditions are fulfilled, ending on the date on which the relevant employees become fully entitled to the award (the vesting period). The cumulative expense recognised for equity-settled transactions at each reporting date until vesting date reflects: 1. the extent to which the vesting period has expired; and 2. the Group’s best estimate of the number of equity instruments that will ultimately vest. No adjustment is made for the likelihood of market performance conditions being met as the effect of these conditions is included in the determination of fair value at grant date. The Consolidated Statement of Comprehensive Income charge or credit for a period represents the movement in cumulative expense recognised as at the beginning and end of that period. No expense is recognised for awards that do not ultimately vest, except for awards where vesting is only conditional upon a market condition. If the terms of an equity-settled award are modified, as a minimum an expense is recognised as if the terms had not been modified. In addition, an expense is recognised for any modification that increases the total fair value of the share-based payment arrangement, or is otherwise beneficial to the employees as measured at the date of modification. If an equity-settled award is cancelled, it is treated as if it had vested on the date of cancellation, and any expense not yet recognised for the award is recognised immediately. However, if a new award is substituted for the cancelled award and designated as a replacement award on the date that it is granted, the cancelled and new award are treated as if they were a modification of the original award, as described in the previous paragraph. The dilutive effect, if any, of outstanding performance rights and share appreciation rights is reflected as additional share dilution in the computation of diluted earnings per share. Significant Accounting Judgements, Estimates and Assumptions The Group measures the cost of equity-settled transactions with employees by reference to the fair value of the equity instruments at the date at which they are granted. The fair value is determined by an external valuation expert using the calculation criteria. 28. Related party disclosures The Group has a related party relationship with its joint arrangements (Note 23), its subsidiaries (Note 24), and its key management personnel (disclosure below). The key management personnel’s remuneration included in General Administration (see Note 2) is as follows: Short-term benefits Other long-term benefits Post-employment benefits Performance Rights and Share Appreciation Rights Total 2020 $ 2019 $ 5,906,298 6,038,132 47,513 244,725 105,207 225,178 2,263,996 2,122,499 8,462,532 8,491,016 115 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 29. Remuneration of Auditors The auditor of Cooper Energy Limited is Ernst & Young Audit services Amounts received or due and receivable by Ernst & Young Australia for: Audit of statutory report of Cooper Energy Limited Other services Taxation and other services Total fees to Ernst & Young 2020 $ 2019 $ 511,395 511,395 187,915 187,915 699,310 390,425 390,425 193,650 193,650 584,075 30. Events after the reporting period On 20 August 2020, Cooper Energy and APA executed a Transition Agreement which outlines terms for the parties to work together to complete the commissioning of the Orbost Gas Processing Plant (OGPP), and commence firm supply to Cooper Energy’s term gas customers as early as possible. The Transition Agreement supplements the existing agreements and sets aside potential claims and entitlements available to either party. It also provides for the sharing of operating costs, capital costs (Phase 2 works) and revenue whilst OGPP commissioning proceeds towards completion. 116 Notes to the Consolidated Financial StatementsFor the year ended 30 June 2020 Directors’ Declaration In accordance with a resolution of the Directors of Cooper Energy Limited, I state that: 1. In the opinion of the Directors: (a) the financial statements and notes of the consolidated entity are in accordance with the Corporations Act 2001, including: (i) giving a true and fair view of the consolidated entity’s financial position as at 30 June 2020 and of its performance for the year ended on that date; and (ii) complying with Australian Accounting Standards (including the Australian Accounting Interpretations) and the Corporations Regulations 2001; (b) the financial statements and notes also comply with International Financial Reporting Standards as disclosed in the Basis of Preparation; and (c) there are reasonable grounds to believe that the consolidated entity will be able to pay its debts as and when they become due and payable. 2. 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 2020. 3. In the opinion of the Directors, as at the date of this declaration, there are reasonable grounds to believe that the members of the Closed Group identified in note 24 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. Signed in accordance with a resolution of the Directors. Mr John C. Conde AO Chairman 31 August 2020 Mr David P. Maxwell Managing Director 117 118 119 120 121 122 123 124 125 Ernst & Young 121 King William Street Adelaide SA 5000 Australia GPO Box 1271 Adelaide SA 5001 Tel: +61 8 8417 1600 Fax: +61 8 8417 1775 ey.com/au Auditor’s Independence Declaration to the Directors of Cooper Energy Limited As lead auditor for the audit of the financial report of Cooper Energy Limited for the financial year ended 30 June 2020, 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 Cooper Energy Limited and the entities it controlled during the financial year. Ernst & Young L A Carr Partner Adelaide 31 August 2020 A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 126 Securities Exchange and Shareholder Information as at 31 August 2020 Listing The company’s shares are quoted on the Australian Securities Exchange under the code of “COE”. Number of Shareholders There were 8,147 shareholders. All issued shares carry voting rights. On a show of hands every member at a meeting of shareholders shall have one vote and upon a poll each share shall have one vote. Distribution of Shareholding (at 31 August 2020) Size of Shareholding Number of holders Number of Shares % of issued capital 1 - 1,000 1,001 - 5,000 5,001 - 10,000 10,001 - 100,000 100,001 - 9,999,999,999 Total Unquoted Options on Issue Nil Unquoted Performance Rights Number of Holders of Rights 53 20 1,036 2,184 1,226 3,080 621 8,147 309,644 5,944,146 10,066,459 108,845,086 1,501,482,063 1,626,647,398 0.02 0.37 0.62 6.69 92.31 100.00 Total Performance Rights 17,862,629 Performance Rights 48,280,025 Share Appreciation Rights Unmarketable Parcels There were 1,579 members, representing 1,017,466 shares, holding less than a marketable parcel of 1,516 shares in the company. Twenty Largest Shareholders Rank Name 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. JP Morgan Nominees Australia Pty Limited HSBC Custody Nominees (Australia) Limited Citicorp Nominees Pty Limited National Nominees Limited BNP Paribas Nominees Pty LtdCS Third Nominees Pty Ltd BNP Paribas Noms Pty Ltd UBS Nominees Pty Ltd INVIA Custodian Pty Limited KAVEL Pty Ltd Mirrabooka Investments Limited CPU Share Plans Pty Ltd Mr Leendert Hoeksema + Mrs Aaltje Hoeksema LEVAK Nominees Pty Ltd Citicorp Nominees Pty Limited Mr Timothy Bryce Kleemann Hooks Enterprises Pty Ltd Farjoy Pty Ltd AMP Life Limited Bond Street Custodians Limited Units % of Issued Capital 416,754,565 333,848,899 191,667,208 78,742,122 51,477,224 33,350,246 27,779,054 22,300,942 14,099,180 12,021,476 11,840,098 11,229,804 8,400,000 6,869,015 5,942,019 5,647,682 5,380,000 4,350,000 4,280,022 3,400,000 25.62 20.52 11.78 4.84 3.16 2.05 1.71 1.37 0.87 0.74 0.73 0.69 0.52 0.42 0.37 0.35 0.33 0.27 0.26 0.21 Totals: Top 20 holders of Ordinary Fully Paid Shares (Total) 1,249,379,556 76.81 Substantial Shareholder The following were substantial holders in the company, as disclosed in substantial holding notices given to the Company as required by section 671B of the Corporations Act. Name of entity Challenger Ltd Mitsubishi UFJ Financial Group, Inc L1 Capital Pty Ltd Greencape Capital CBA Carol Australia Holdings Pty Ltd H.E.S.T Australia Ltd as Trustee for Health Employees Superannuation Trust Australia Number of securities in which substantial shareholder has a relevant interest as at date of last notice Voting power as at date of last notice 151,257,525 123,182,306 118,515,228 114,820,320 104,143,176 97,203,575 81,518,090 9.30% 7.50% 7.29% 7.06% 6.40% 5.99% 5.01% 127 Shareholder Information Enquiries and share registry address Shareholders with enquiries about their shareholdings should contact the company’s share registry, Computershare Investor Services Pty Ltd, via the telephone contact above. Online shareholder information Shareholders can obtain information about their holdings or view their account instructions online, as well as download forms to update their holder details. For identification and security purposes, you will need to know your Holder Identification Number (HIN/SRN), Surname/Company Name and Post/Country Code to access. This service is accessible via the Computershare website. Change of address Shareholders who have changed their address should advise Computershare in writing. Written notification can be mailed or faxed to Computershare at the address given above and must include both old and new addresses and the security holder reference number (SRN) of the holding. Annual Report This document has been prepared to provide shareholders with an overview of Cooper Energy Limited’s performance for the 2020 financial year and its outlook. The Annual Report is mailed to shareholders who elect to receive a copy and is available free of charge on request (see Shareholder Information printed in this Report). The Annual Report and other information about the company can be accessed via the company’s website at www.cooperenergy.com.au Annual General Meeting Date of meeting: Thursday, 12 November 2020 Time of meeting: 10:30 am (Australian Central Daylight Time) Place of meeting: Due to Federal and State Government restrictions regarding gatherings and COVID-19 the meeting with be held virtually via an online platform at https://web.lumiagm. com with meeting ID 376-666-802 The Notice of Meeting has been mailed to shareholders. Additional copies can be obtained from the company’s registered office or downloaded from its website at www.cooperenergy.com.au Abbreviations and terms This Report uses terms and abbreviations relevant to the Group, its accounts and the petroleum industry. The terms “the Company” and “Cooper Energy” and “the Group” are used in the report to refer to Cooper Energy Limited and/or its subsidiaries. The terms “2020”, or “2020 financial year” refer to the 12 months ended 30 June 2020 unless otherwise stated. References to “2021”, or other years refer to the 12 months ended 30 June of that year. 128 Change of address forms are available for download from the Computershare website. Alternatively, holders can amend their details on-line via the Computershare website. Shareholders who have broker sponsored holdings should contact their broker to update these details. Annual Report mailing list Shareholders who wish to vary their annual report mailing arrangements should advise Computershare in writing. Electronic versions of the report are available to all via the company’s website. Annual Reports will be mailed to all shareholders who have elected to be placed on the mailing list for this document. Report election forms can be downloaded from the Computershare website. Forms for download All forms relating to amendment of holding details and holder instructions to the company are available for download from the Computershare. Other abbreviations bbl: barrels of oil boe: barrels of oil equivalent bopd: barrels of oil per day $: Australian dollars E&P: exploration and production FEED: front end engineering and design FID: final Investment decision FTE: full time equivalent GJ: gigajoules HSEC: Health, safety, environment and community kbbl: thousand barrels km: kilometres LNG: liquefied natural gas LTI: lost time injury LTIFR: lost time injury frequency rate m: metres MMbbl: million barrels of oil MMboe: million barrels of oil equivalent MM scfg/day: million standard cubic feet of gas per day NOPSEMA: National Offshore Petroleum Safety and Management Authority NOPTA: National Offshore Petroleum Title Administrator PJ: petajoules PRMS: Petroleum Resources Management System SCF: standard cubic feet SPE: Society of Petroleum Engineers TJ: terajoules TRIFR: Total recordable injury frequency rate 1C: Low Estimate Contingent Resources 2C: Best Estimate Contingent Resources 3C: High Estimate Contingent Resources 1P: Proved Reserves 2P: Proved and Probable Reserves 3P: Proved, Probable and Possible Reserves VWAP: volume weighted average price Investor information Information about the company is available from a number of sources: • Website: www.cooperenergy.com.au • E-news: Shareholders can nominate to receive company information electronically. This service is hosted by Computershare and can be accessed via Computershare’s website • Publications: the annual report is the major printed source of company information. Other publications include half-yearly and quarterly reports, company press releases, investor packs, and presentations. All publications can be obtained either through the company’s website or by contacting the company • Telephone or email enquiry: to Don Murchland, Investor Relations +61 439 300 932; donm@cooperenergy.com.au Reserves and resources Cooper Energy reports its reserves and resources according to the SPE (Society of Petroleum Engineers) Petroleum Resources Management System guidelines (PRMS). Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies. In PRMS, the range of uncertainty is characterised by three specific scenarios reflecting low, best and high case outcomes from the project. The terminology is different depending on which class is appropriate for the project, but the underlying principle is the same regardless of the level of maturity. In summary, if the project satisfies all the criteria for Reserves, the low, best and high estimates are designated as proved (1P), proved plus probable (2P) and proved plus probable plus possible (3P), respectively. The equivalent terms for contingent resources are 1C, 2C and 3C. Rounding Numbers in this report have been rounded. As a result, some figures may differ insignificantly due to rounding and totals reported may differ insignificantly from arithmetic addition of the rounded numbers. Corporate Directory Directors John C Conde AO, Chairman David P Maxwell Timothy G Bednall Victoria J Binns Elizabeth A Donaghey Hector M Gordon Jeffrey W Schneider Alice J Williams Company Secretary Amelia Jalleh Registered Office and Business Address Level 8, 70 Franklin Street Adelaide, South Australia 5000 Telephone: + 618 8100 4900 Facsimile: + 618 8100 4997 E-mail: customerservice@cooperenergy.com.au Website: www.cooperenergy.com.au Perth Office Level 15, 123 St Georges Terrace Perth, Western Australia 6000 Telephone: +61 8 6556 2101 Facsimile: +61 8100 4997 Auditors Ernst & Young 121 King William Street Adelaide, South Australia, 5000 Solicitors Johnson Winter & Slattery Level 9, 211 Victoria Square Adelaide SA 5000 Bankers Australia and New Zealand Banking Group Limited 11-29 Waymouth Street Adelaide, 5000 South Australia NATIXIS Level 26, 8 Chifley Square Sydney NSW 2000 ABN AMRO Bank N.V. Level 11, 580 George Street Sydney NSW 2000 Australia ING Bank N.V. Sydney Branch Level 31, 60 Margaret Street Sydney NSW 2000 National Australia Bank Limited Level 32, 500 Bourke Street Melbourne VIC 3000 Share Registry Computershare Investor Services Pty Limited Level 5, 115 Grenfell Street Adelaide SA 5000 Website: investorcentre.com/au Telephone: Australia 1300 655 248 International +61 3 9415 4887 Facsimile: +61 3 9473 2500