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Annual Report 2018

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for south-east Australia 2 0 1 8 A n n u a l R e p o r t 2018 Annual Report Cooper Energy Limited ABN 93 096 170 295 Cover: Flow testing of Sole-3, the first of two new production wells spudded in the Gippsland Basin during the year to bring a new source of gas supply to south-east Australia from July 2019. The completion of Sole-3 and Sole-4 after year-end was the successful culmination of workstreams across the company during the year, spanning financing, legal, subsurface, technical, procurement, development, drilling, safety and environment and project management. This report features photographs of operations on the Diamond Offshore Ocean Monarch drilling rig and support craft on location at Sole. Annual Report This document has been prepared to provide shareholders with an overview of Cooper Energy Limited’s performance for the 2018 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 Notice of Meeting The 2018 Annual General Meeting of Cooper Energy Limited ABN 93 096 170 295 (“the company”) will be held at 10.30 am (ACDT) on Thursday, 8 November 2018 in the PwC Building, Level 11, 70 Franklin Street, Adelaide, South Australia. 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 abbreviations and terms relevant to the company’s accounts and the petroleum industry. The terms “the company” and “Cooper Energy” and “the Group” are used in this report to refer to Cooper Energy Limited and/or its subsidiaries. The terms “2018”, “FY18” and “2018 financial year” refer to the 12 months ended 30 June 2018 unless otherwise stated. References to “2017”, “FY17, FY19” or other years refer to the 12 months ended 30 June of that year. Other abbreviations bbl: barrels of oil boe: barrels of oil equivalent bopd: barrels of oil per day $: Australian dollars 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 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 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. Cooper Energy We find, develop and commercialise oil and gas. We do this with care and strive to provide attractive returns for our shareholders and good commercial outcomes for our customers. 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 7 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 Our business We generate revenue from the discovery, commercialisation and sale of gas to south-east Australia and low cost 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 development decision within 5 years; and • are value accretive. Production FY18 1.49 MMboe 0.27 Proved and Probable Reserves 52.4 MMboe at 30 June 2018 Contingent Resources 23.6 MMboe at 30 June 2018 1.8 10.0 0.1 3.1 1.22 40.6 20.4 Gippsland Basin gas Cooper Basin oil Otway Basin gas and gas liquids Other key statistics: For the year ended 30 June 2018 Market capitalisation: Net cash/(debt): Issued shares: Shareholders: $616 million $111 million 1,601.1 million 6,622 Employees and contractors: 101 full time equivalent 2 Offshore Otway Basin: Gas production and exploration • Casino Henry gas production and development • Minerva gas field • Minerva Gas Plant • VIC/P44 exploration Gippsland Basin: Offshore gas development and exploration • Sole Gas Project • Manta gas and liquids resource • VIC/P72 exploration permit Darwin Perth Office Brisbane Adelaide Office Sydney Melbourne Onshore Otway Basin: Gas exploration • Gas exploration acreage • Extends over Sawpit sandstone play fairway and surrounds Haselgrove discovery Hobart Cooper Basin: Onshore oil production • Western flank oil production and exploration 3 Key results Financial • Sales revenue up 73%, chiefly due to increased gas volumes and assisted by higher oil and gas prices. • Statutory profit of $27.0 million includes significant items of $17.2 million, including gain on sale of Orbost Gas Plant. • Return to profit at statutory and underlying profit levels after tax. • Balance sheet cash and debt up due to Sole project funding and draw-downs. Sales revenue $ million Statutory net profit after tax $ million Underlying net profit after tax $ million 9.8 67.5 27.0 39.1 39.1 27.4 -12.3 -34.8 -63.5 -1.3 -2.8 -8.7 2015 2016 2017 2018 2015 2016 2017 2018 2015 2016 2017 2018 Net cash from operating activities $ million Net cash/(debt) $ million Shareholders equity $ million 22.2 147.4 111.0 443.9 285.0 7.9 4.1 2.0 49.8 39.4 103.9 91.6 2015 2016 2017 2018 2015 2016 2017 2018 2015 2016 2017 2018 4 Operations and reserves • Zero lost time injuries, zero serious injuries, zero reportable environmental incidents. • Production up 54%, with full year contribution from gas assets acquired in FY17. • Proved and probable reserves up 348%; Sole FID and upgrades from field performance. Safety Lost time injury frequency rate Production MMboe Proved and probable reserves MMboe 1.0 1.49 0.96 52.4 0.48 0.46 0.0 0.0 0.0 11.7 3.1 3.0 2015 2016 2017 2018 2015 2016 2017 2018 2015 2016 2017 2018 Equity Share price cents at 30 June 24.5 21.5 Basic earnings per share cents Market capitalisation $ million at 30 June 38.0 38.5 1.8 -1.8 -10.1 -19.2 616 433 81 94 2015 2016 2017 2018 2015 2016 2017 2018 2015 2016 2017 2018 5 Overview of operations, exploration and development Otway: Value adding development and gas contracting. Plant acquisition agreement. • Production increase at Casino Henry by workover of Casino-5 gas well • New gas supply contract for supply from Casino Henry to Origin Energy from 1 March 2018 to 31 December 2018 • Minerva gas production exceeding expectations: reserves upgrade and field life extension • Gas plant acquisition agreement for Casino Henry JV to acquire Minerva Gas Plant on fulfilment of conditions • Exploration and development analysis and planning for drilling in FY19 and FY20: Henry development; offshore and onshore exploration drilling Cooper Basin: Increased production. Strong cash margin. • Production: oil production up 8% • Direct operating cost: A$33.05/bbl vs average oil price A$85.55/bbl • Drilling: 2 unsuccessful exploration wells drilled Minerva Gas Plant 6 Callawonga storage facility Gippsland: Sole Gas Project proceeding, exploration acreage acquired. • Sole Gas Project FID occurred 29 August 2017 with securing of funding • Orbost Gas Plant agreement completed in October providing for APA Group to acquire and upgrade the plant to process Sole gas and access for Manta • Project on schedule: Sole Gas Project advanced to 56% complete at 30 June • Key milestones completed include shore crossing and drilling of production wells after year-end • Project safety record: offshore drilling campaign completed without lost time injuries or environmental incidents • Manta gas and gas liquids appraisal and exploration preparations advanced for drilling in FY20 • Exploration acreage acquired: VIC/P72, adjacent to existing acreage and in proximity to Sole and Orbost Gas Plant Supply vessel Sea Swan and Diamond Offshore Ocean Monarch drilling rig Production: 12 months to 30 June 2018 2017 Gas PJ Oil million barrels Total MMboe Gas PJ Oil million barrels Total MMboe Otway Basin 7.0 Cooper Basin Indonesia - - - 0.27 - 1.22 0.27 - 4.0 - - - 0.25 0.03 0.68 0.25 0.03 • FY19 outlook: Sole project completion scheduled for June, preparation for Manta drilling, VIC/P72 study and analysis 7 From the Chairman John Conde AO transformational growth in its production, cash flow and earnings and of delivering the first new offshore gas supply to south-east Australia in 6 years. It is our expectation shareholder value recognition will accompany progress in the Sole Gas Project. This was evidenced post year-end by the improvement in the company’s share price following completion of the project’s production wells. Safety continues to be our top priority and operating with care for health and safety, the environment and our communities is one of our core values. We have retained this focus on the safety of our staff, our contractors and the communities in which we operate, embracing the added demands the company’s development continues to bring for safe management of our operations. The 2018 financial year brought marked expansion in the scope, risk profile and nature of your company’s responsibilities. Apart from taking on the role of Operator from 1 July 2017 for a number of offshore permits, activities undertaken included the conduct of an offshore drilling campaign and a range of onshore work for the Sole Gas Project including pipe welding, earthworks and the drilling of two shore crossings. This was completed without lost time injuries, serious injuries or reportable environmental incidents. However, as this report documents, the occurrence of two contractor restricted work cases meant our performance ultimately fell short of the injury-free and incident-free performance to which we aspire. The board is committed to an injury-free and incident-free performance and we will continue to encourage all employees and our contractors to strive for this outcome. As set out in the opening page of this report, Cooper Energy is a values-driven organisation. The values stated and elaborated have been a longstanding feature of the company, its culture and decision-making process. Accordingly, it was pleasing the company’s inaugural staff engagement survey conducted after year-end confirmed an exceptionally high level of engagement and awareness and acceptance of the Cooper Energy Values and their importance in generating shareholder value. We were pleased to welcome Ms Elizabeth Donaghey to the board in June. Ms Donaghey brings to your board extensive experience, including as a director, within the Australian energy sector. In particular, her experience in gas commercialisation, strategy and portfolio management, sustainability and regulatory matters is directly relevant to your company’s present and future needs. We thank the Managing Director, David Maxwell, and his team of executives and staff for their contribution to what has been a landmark year for your company, positioning us on the cusp of substantial growth. Congratulations all! Finally, I thank my colleagues on the board and our Company Secretary for their counsel, effort and support and for the many unscheduled meetings and discussions the year’s activities required. This annual report is the most pleasing I have had the honour of presenting as the chairman of your company. There are three reasons for this. First, as this document details, the growth and progress during the 12 months to 30 June has been exceptional in almost every metric of financial and technical performance. Profit and cash generation have improved several times over. Production was 54% higher and exceeded expectations at the start of the year. Proved and Probable reserves were more than 4 times greater than at the start of the year. The company’s financial position and outlook at year-end were strong. Secondly, and more significantly, I am conscious Cooper Energy shareholders placed their trust in the execution of a long-term strategy under which a company, which had no gas assets, would build a gas business to address supply opportunities expected to emerge in six or more years’ time. I am pleased this report, the first documenting a full 12 months’ performance as a predominantly gas business, demonstrates clear progress and benefits brought by this strategy. At year-end this progress had not translated fully to shareholder value as measured by share price, which grew by 1.3% to 30 June compared to the 42% increase in market capitalisation. Total Shareholder Return, inclusive of the discounted share offers made as part of the Sole Gas Project funding, was 6.0%. The discrepancy between the growth in market capitalisation and share price during the year is due to this capital issue, which secured conservative funding from top-tier Australian and international banks and the Final Investment Decision for the Sole Gas Project. While the increased share base has diluted prices per share, we are confident the forging of relationships with a quality banking group and the calibre of the finance package secured will benefit shareholders in the medium and long terms. Thirdly, the outlook for the coming years foreshadowed in this report is particularly promising. John Conde AO Chairman After six years of strategy development, portfolio building, planning and funding, your company is now within 12 months of realising 8 On-board the Ocean Monarch, a subsea wellhead is prepared for deployment on the seabed. The wellhead is 5 metres high and weighs 35 tonnes. 9 Managing Director’s Report Putting a good set of results in the right context and our preparations for ‘growth after Sole’. David Maxwell 2018 The 12 months to 30 June 2018 proved to be the most significant year for Cooper Energy since its incorporation. 2018 was the year the company made the commitments, received the necessary approvals and executed agreements which underpin its transformation from a minority interest onshore oil producer to an operator, developer and explorer of offshore gas for south- east Australia. The approvals, commitments and agreements formalised during the year included: - regulatory approvals and acceptances for assumption of the role of Operator for our Sole and Casino Henry projects, the associated pipeline interests and our offshore exploration acreage; - funding agreements secured with senior bank lenders; - Final Investment Decision (FID) for the Sole Gas Project; - agreement with APA Group (“APA”), for APA to acquire, upgrade and operate the Orbost Gas Plant to process gas from Sole, and later, Manta and other fields; - new sales agreements for Casino Henry gas, the first since the company acquired the asset and the first since agreements struck when the field commenced production in 2006; and - agreement for the Casino Henry joint venture to acquire the Minerva Gas Plant. Cooper Energy is now positioned and equipped to deliver the shareholder value targeted by the gas strategy to which the company committed in 2012. It is important to understand this expectation is based on more substantive factors than simply building a gas business to capture supply opportunities. The focus on building a business best able to generate shareholder value from the opportunity in south-east Australian gas has given Cooper Energy 3 ‘competitive edges’ which, in combination, differentiate the company from its peers and are expected to drive value creation in the coming 2 to 3 years: 1) the growth profile from Sole. The Sole Gas Project is scheduled to underpin an increase in gas production over 2018 levels of more than 3 times in its first full year of operation, with flow-on gains in revenue and cash generation. Sole is projected to add gas sales of 24 petajoules per annum on commencement which compares to Cooper Energy’s total FY18 gas output of 7 petajoules. Subsea wellhead enters the waters of Bass Strait as it is lowered for installation on the Sole-4 production well, 125 metres below surface. Fellow shareholders, Your company’s annual results for 2018 are the best yet recorded by Cooper Energy. Among the highlights are its highest production, strong financial results and its greatest growth in Proved and Probable reserves. However, while annual reports necessarily focus on a 12-month period, the building of businesses and creation of sustainable shareholder value is a longer-term exercise. The achievements featured in this report have emerged from the execution of a strategy, over six years, by a stable, committed management team, backed by a supportive loyal shareholder base, to build a portfolio-style gas business addressing supply opportunities in south-east Australia. And while it is pleasing to report the results this enabled in 2018, we are mindful genuine value creation for our shareholders requires ongoing, and greater, improvement. Cooper Energy is well placed to deliver this; the results for 2018 are but a small, and second-year, instalment of the six-year growth profile expected from the company’s existing developed assets and projects. However, critical assessment of your company’s capacity to deliver sustained improvement requires more than the simple year- on-year comparisons that occupy an annual report. In this, my sixth annual report, I will address our position at year-end and review the progress, suitability and resourcing of our strategy. 10 11 Managing Director’s Report David Maxwell 2) the competitiveness of our gas portfolio and volume of uncontracted gas. Cooper Energy’s reserves include one of the larger inventories of uncontracted gas, located in the most competitive sources of supply for south-east Australia. Your company is among the very best placed to bring gas to this tightly supplied region. Moreover, the capacity to portfolio manage supply across two hubs in the Otway and Gippsland basins enables Cooper Energy to optimise its supply for best returns. 3) incumbency as an existing operator in the most competitive sources of gas supply for south-east Australia. Our status as one of the few offshore Operators of oil and gas assets in offshore southern Australia, positions Cooper Energy as one of the small number of companies ready, with the necessary resources and the history of compliance relevant for exploration, development and production of gas offshore Victoria. As a result, the company offers greater value and desirability as a partner in the region and possesses advantages in the ease, speed and cost with which it can address local opportunities. This is enhanced further by the access to infrastructure Cooper Energy holds through its agreements for processing at the Orbost Gas Plant and the agreement to acquire the Minerva Gas Plant. Leveraging of these advantages commenced in FY18 with the tendering of Casino Henry gas supply for the 2018 calendar year and is expected to accelerate in FY19. The conclusion of a new gas supply agreement for Casino Henry gas for the 2019 calendar year, the tendering of uncontracted gas from Sole and the safe completion of the Sole Gas Project to budget are among the events projected to be value-adding in the new year. Operating with care and sustainably The growth of our business has brought attendant growth in the scope, and depth, of the obligations we assume in choosing to operate with care for the health and safety of our people, the environment and communities with which we are involved. In 2018 this involved the performance of 491,111 hours of work by employees and contractor staff including offshore workover and drilling operations in the Otway and Gippsland basins, support of these campaigns through the Port of Melbourne supply base and site construction works at the Orbost Gas Plant for the shore crossings. The conduct of operations that were safe and environmentally responsible, is but a small outcome of the larger task involved in planning, documentation, consultation, securing regulatory approval, exercise drills, testing, review and improvement. Assuming operatorship of offshore licences, and the obtaining of approvals necessary for a 120-day drilling campaign in 3 locations, required extensive work to secure regulatory acceptance of the company’s safety and environmental management plans. The safe execution of the drilling program without environmental incident is a noteworthy accomplishment for which I would like to record the company’s commendation to all involved. In terms of measured performance, the company completed the year with no serious injuries, environmental or process safety incidents. There were two restricted work-related incidents involving contractor employees which resulted in a total recordable injury frequency rate of 4.07 for the 12 months to 30 June, which compares to 1.98 for the preceding 12 months, and the industry standard of 4.02 as measured by NOPSEMA (National Offshore Petroleum Safety and Environmental Management Authority). Discussion of these results is provided in more detail under the heading ‘Safety’ on page 19. A safe workplace requires no serious harm to our workers, 365 days of the year. The company achieved this and is committed to maintaining this standard. We are conscious a sustainable business demands more than compliance to the minimum safety, environmental and social standards considered necessary. The past 18 months have been necessarily focussed on rapid attainment of regulatory compliance and safe execution. We have now elevated our aspirations to the achievement of ‘best in class’ standards. Capital management The financial close of the $265 million bank facilities in October 2017 was a milestone for the company. The facilities, which completed funding for the Sole Gas Project, were underwritten by ANZ and Natixis, with ABN AMRO, ING and NAB joining via subsequent syndication. The participation of top-tier banks and the terms of the facility reflect favourably on the credit quality of the Sole project and of Cooper Energy. The principal facility, a $250 million reserve-based lending facility extends over the life of the field. I would like to record our appreciation to the members of our banking syndicate for the long- term commitment they have made to the company which enabled the development of the cornerstone project for our growth plans. It is our expectation the banking facility and the relationships we have established with senior banks will prove important in the execution of our growth plans in the coming years. Future growth The progression of the Sole Gas Project towards its scheduled completion by July 2019 has been accompanied by increasing work on the company’s next wave of growth. A number of opportunities for production uplift from 2020 onwards are present within our portfolio. While these cover a range of exploration, appraisal and development opportunities, all share the competitiveness characteristics that enhance development prospects and value creation: proximity to existing infrastructure, proximity to market and relatively low capital costs. 12 Concluding comments Your company has concluded the 2018 financial year with the Sole project fully funded and advancing to its July 2019 start-up and the transformative uplift in production, revenue and cash generation this will bring. Having reached this position, our focus in 2019 will be on efficient execution and operating safely in accordance with our values of care, integrity, fairness and respect, transparency, collaboration, awareness and commitment. While our year-end reserves and outlook are the strongest yet for Cooper Energy we are mindful value for shareholders requires the potential of our portfolio to be realised. I want to acknowledge and record my thanks to the staff and contractors who have made the pleasing results of 2018 possible. David Maxwell Managing Director Preparations have commenced for the conduct of a drilling campaign to address these opportunities which include: - Henry development; this well is to address approximately 24 PJ of undeveloped proved and probable reserves net to Cooper Energy and lift field production. The well would be connected at the first opportunity and is expected to provide an immediate uplift in production. - Manta-3; to be drilled as a precursor to a development decision on the Manta Gas Project. Manta is 100% owned by Cooper Energy and offers a second-stage and synergistic gas and liquids development to the nearby Sole gas field. It is considered Manta could be developed to commence production from FY23, subject to rig availability, drilling and development outcomes. Access to gas processing at the Orbost Gas Plant has been secured under the existing agreement with APA and there is customer interest in the availability of Manta gas. Subject to the results of Manta-3, it is considered the field’s contingent resources of 106 PJ to 111 PJ of gas and 3.2 million barrels of condensate can be developed via a subsea project similar to that being applied at Sole. The well also has an exploration purpose, as it will address the deeper, larger, prospective gas resource discussed on page 33. - gas exploration targets in the company’s offshore Otway Basin acreage where success rates are high and infrastructure is in place. As discussed in the Review of Operations on page 31, analysis has identified a number of attractive prospects which are considered likely to be economic for development given the proximity to established pipelines and the availability of the Minerva Gas Plant on completion of its acquisition from BHP Billiton Petroleum (Victoria) Pty Ltd. These opportunities offer significant increments to our gas production in the period 2020 to 2025. More importantly, it is considered each opportunity satisfies the company’s 3-step screen for value generating capital expenditure: a superior position on the cost curve; economics which are value generating and either in production or likely to be ready for a development decision within 5 years. The potential of these opportunities, coupled with south-east Australia’s ongoing gas requirements, underpin Cooper Energy’s firm conviction the existing portfolio has the ingredients to deliver the company’s next wave of growth after Sole. Our exploration and development activities for the coming 12 to 24 months will be directed to transforming these opportunities into committed growth projects. The question of strategy and our future opportunities are examined in a broader context on the following pages. 13 Strategy and the delivery of value for shareholders. 6 questions, 6 years in. In 2012 the company elected to reorient its strategy from onshore Cooper Basin oil production and international exploration to build a portfolio style gas business to address supply opportunities foreseen emerging in eastern Australia following the commencement of LNG manufacture and export. Six years on, it is appropriate to review the strategy and its progress. Managing Director David Maxwell addresses six questions on its ongoing relevance, shareholder benefits and the future. 1. The gas strategy was launched 6 years ago. 3. So what is the company’s position now? Is it still appropriate? The underlying premise of the strategy adopted in 2012 has been proven correct, albeit conservative. The gap between forecast south-east Australian gas demand and available supply has emerged earlier and larger than anticipated. Gas prices have also been higher than anticipated. Our gas assets are considered to be among the lowest cost supply options for south-east Australia for the foreseeable future. The more we examine the assets we have acquired, the more opportunities we see to underpin sustained growth in production and value. 2. Is the company progressing satisfactorily against its strategy and its opportunity horizon? We are tracking ahead of where we expected to be. Remember, we had no gas reserves, gas contracts or gas prone exploration acreage when we committed to our gas strategy. Our equity in our principal gas assets in the offshore Otway and Gippsland Basin is 50% to 100%, much higher than we had anticipated, and we are also Operator for these assets. The four years to 2016 were concerned with patient compilation of assets that met our criteria for value generation and the orderly divestment of non-core assets. By January 2017, we had assembled a portfolio of gas production, exploration and development assets in the Otway and Gippsland basins. From 2017, the focus has been on funding and development. The company is on track to be producing gas from both the Otway and Gippsland basins by mid-2019, all from Cooper Energy- operated assets. Completion of the Sole Gas Project at this time and of the Henry development well later in the year will have our gas production growing and the capacity to apply a portfolio approach to supply. When should shareholders expect to see the delivery of value targeted by the strategy? We now have the foundation portfolio in place for execution of the strategy and we expect these assets will be delivering transformative production and financial growth within 12 months. Our expectation is this should be reflected in the value of the company’s securities, as should the de-risking of the Sole project as it nears completion. The 29% increase in the share price in the 8 weeks following the completion of the first of the Sole production wells is illustrative of this. 4. Should there be a change in strategy given the company has progressed from an aspiring gas supplier to an established gas supplier to south-east Australia? Our strategy for creating shareholder value is essentially unchanged: a portfolio style gas business generating the bulk of its revenue from the supply of gas to south-east Australia from resources that occupy a highly competitive position on the cost curve; that are value adding; and that are either in production or have clear plans for production within 5 years. The qualification on competitiveness, value accretion and development timelines are critical for our business model. Only the most competitively placed resources can generate the best returns to shareholders and the best commercial outcomes for customers. This remains the bedrock of our strategy. What does change is the focus and scale of our activities. With the foundation in place, the focus of our activities has shifted to efficient exploration, development, excellence in operations and gas contracting so we get the best value for our shareholders – whilst at all times ensuring we manage and conduct our operations every day with care. 14 6. Does Cooper Energy have the resources to deliver on its strategy? This is a question we continue to ask ourselves and we work hard to make sure the answer is “yes”. It is a question which extends beyond financial capability; along the journey we have had to assess, build, prove and test our technical, managerial and operational depth. We have been fortunate to have acquired a proven team of employees and contractors. This team has driven what has been a successful drilling work program at Casino and Sole this year. We have been rounding out our team with appointments where needs are identified, staying disciplined in making sure Cooper Energy stays a lean organisation, works consistent with our Cooper Energy Values whilst being fit for purpose. Developing our people, attracting good people and working with experienced capable contractors has been an important part of our success – and we don’t plan on changing this. This approach has been critical, as our journey from being a company with a market capitalisation of $50 million in January 2016 proposing to develop the $605 million Sole Gas Project, could seem daunting to some. At Sole, the involvement of blue-chip partners, customers, suppliers and contractors such as APA, AGL, EnergyAustralia, Alinta, O-I, GE, Diamond Offshore, Subsea7 and Technip along with senior bankers ANZ, Natixis, ABN AMRO, ING and NAB, has created a low risk, soundly-based project that is conservatively and fully financed. Our financial capacity will expand substantially with the completion of the Sole Gas Project and the boost from cash generated by the commencement of gas supply from Sole. We expect this to support the execution of our drilling campaign commencing in 2019 and our development plans at Henry and the Minerva Gas Plant. We are continuing to develop and grow our portfolio, as resource companies must. We continue to evaluate opportunities that meet our criteria, most recently adding the VIC/P72 exploration acreage that adjoins some of our existing acreage and infrastructure in the Gippsland Basin. 5. What about after Sole? Our expectation and planning now is for a ‘second wave’ of production growth from our existing portfolio from 2022/2023. The preparation of an offshore drilling campaign to address these opportunities has been identified as one of our most important workstreams for FY19. We have commenced engagement with rig contractors for a program which is expected to include appraisal and exploration drilling on the Manta gas field and, subject to joint venture approval, the drilling of the Henry development well and at least 2 exploration wells in the offshore Otway Basin. We expect the drilling campaign will commence some time in calendar 2019, at a date that will be largely determined by rig availability. Our development concept for Manta is advancing and has benefited from the work done on Sole, our existing infrastructure at Patricia-Baleen and access agreements for the Orbost Gas Plant. Success at Manta-3 should see FID for that project within 12 months thereafter. Our offshore Otway acreage is particularly attractive for gas exploration and development. Its exploration merit is enhanced by the clarity of seismic data, the number of prospects and the drilling success rate in a proven gas province. The development attractiveness is enhanced by the proximity of existing pipeline and competitive processing infrastructure. Our subsurface team is working hard to identify the best targets for the VIC/P44 joint venture to consider and select for drilling in the approaching offshore drilling program. Our commitment to acquire the Minerva Gas Plant from BHP is indicative of the promise we see for further gas development in the Otway Basin. It is worth reflecting on the features of the plant that suggest its strategic and financial value will increase significantly in the coming years: it is an established gas plant with available processing capacity, offering competitive processing costs, at low inlet pressure, to the existing fields nearby and is located in a proven gas producing province that has the highest success rate for offshore gas exploration in southern Australia. We also plan to participate in the drilling of an onshore well in the South Australian Otway Basin in FY19. 15 2018 Sustainability Review Cooper Energy is committed to operating with care and seeks to impart a legacy of positive social, environmental and economic outcomes through its operations and behaviours. The company’s objective is to be a sustainable business that delivers value for shareholders, customers, employees and the communities in which it works. The pursuit of sustainability is conducted through two dimensions: firstly, in the present, by seeking to operate with excellence 365 days a year, at every location where the company is involved; and secondly, in building better outcomes in the future through continual improvement in performance. The company’s efforts are guided by the sustainability principles developed and applied across 4 key areas: people; safety; environment; and community and stakeholders. The opportunities, obligations and exposures in each of these areas expanded substantially with the company’s development during the year. Cooper Energy’s transition from a non-operating onshore oil producer to the Operator of numerous offshore petroleum titles with operations ranging from exploration, project development, production and care and maintenance has brought new requirements and risks to be carefully managed in the interests of sustainability. This review, is just one of a number of governance and reporting measures instituted for monitoring, managing, reporting and improving the company’s performance in building a sustainable business. At the board level, the governance of performance in promoting and achieving sustainability has been given extra focus through the formation of a specific Risk and Sustainability Committee. Under the guidance of the Risk and Sustainability Committee, the company developed a Sustainability Policy and prepared this Sustainability Review for inclusion in the 2018 Annual Report, to explain the approach taken, and performance and areas of future focus. This sustainability review is the first by Cooper Energy. The company looks forward to building the scope and depth of its reporting and to publishing performance and progress on an annual basis in future years’ Sustainability Reviews. 16 Ocean Monarch conducting flow-back operations on the Sole gas field, VIC/L32, Gippsland Basin 17 2018 Sustainability Review Safety The last 12 months has seen Cooper Energy mature as an operator. The expansion in the scope and nature of Australian operations brought increased activity, work hours and contractor management requirements and increased exposure to risk. This expansion was executed without a single Lost Time Injury (LTI) or serious injury being recorded during the year. Hydrogen sulphide safety drill on-board Ocean Monarch 18 Key Performance Indicators Lost Time Injury Frequency Rate Total Recordable Injury Frequency Rate Recordable Incidents Serious Injuries Process Safety Incidents Work Hours Australian Operations Work Hours Total FY18 0 4.07 2 0 0 491,111 491,111 FY17 0 1.98 1 0 0 58,312 506,298 Cooper Energy takes a proactive approach to the achievement of and maintenance of an incident-free, safe performance, every day, at every location it is operating. Fundamental to the creation and maintenance of a safe work place is the application of the corporate values as a guiding tool for all decisions made, followed by disciplined performance in the workplace so performance aligns with our objectives. Safety performance Personal safety performance is measured in terms of the total recordable injury frequency rate (TRIFR) and lost time injury frequency rate (LTIFR). Cooper Energy recorded a TRIFR of 4.07 in line with the NOPSEMA industry average. There were two restricted work cases involving contractor employees. Both these cases were soft tissue injuries with the workers making full recoveries. Of note, is zero lost time incidents and no serious process safety incidents during the year. Every day should be incident-free and although there were no serious injuries throughout the year, the lessons learnt from all incidents and near misses have helped Cooper Energy to take proactive steps to strengthen safety performance. Performance summary during the year P No Lost Time Injuries P No serious recordable injuries P No serious process safety incidents P Ongoing refinement of management systems P Successful launch of a cloud-based emergency response platform for collaboration across locations P Positive regulator evaluation of HSEC systems Future focus ¢ Ongoing refinement of HSEC systems ¢ Improved leading key performance indicators to drive compliance and continual improvement ¢ Refined measurement of incident investigation metrics ¢ Timely close-out of action items identified in audits ¢ Strengthen contractor HSEC evaluation and onboarding 19 2018 Sustainability Review Environment Cooper Energy is committed to doing no environmental harm through proactive planning and management of all campaigns. The operation of the company’s first offshore drilling campaign required the preparation, approval and implementation of comprehensive and detailed environmental management plans. The drilling campaign was completed with no spills to the environment. Environmental performance Performance summary There were no reportable incidents1 in Cooper Energy’s operations during the year. Cooper Energy’s implementation of its no harm policy has focussed on two elements during the year: 1. Implementation of systems that capture potential impacts and risks to the environment (during activity pre-planning risk assessments); identifying and managing these risks with mitigating control measures to the industry standard level of ALARP (“as low as is reasonably practical”), a level that meets environmental commitments as detailed in the Environment Plans submitted to and accepted by the Commonwealth and State regulators; and 2. Expanding environmental expertise to ensure coverage and knowledge across diverse areas of operation, both onshore and offshore. P No reportable environmental incidents P No environmental spills or serious environmental incidents P No environmental improvement or infringement notices P Growing in-house environmental expertise Future focus ¢ Consolidate offshore environmental documentation ¢ Streamline environmental commitments ¢ Focus on bioregions ¢ Continue to protect sensitive environments 1. A reportable environmental incident means an incident relating to the activity that has caused or has the potential to cause moderate to significant environmental damage. These are defined in the title- holder’s environment plan. Key measures Key performance indicator Environmental Spills Regulator Environmental Inspections Serious Environmental Incidents Environmental Improvement Notices FY18 0 2 0 0 FY17 0 1 0 0 20 East Gippsland shoreline. Cooper Energy’s operations during the year required the preparation of comprehensive environmental management plans for marine and shoreline environments in the Gippsland and Otway Basins. 21 2018 Sustainability Review Our People – One Team FY18 was a period of exciting and transformational growth. The significant contribution of people and the focus on what needs to be achieved and how to achieve these objectives are equally important. Workforce capability has strengthened and priorities for further organisation development are identified. At Cooper Energy, values are at the heart of the organisation’s culture. The Cooper Energy Values are the guiding principles which describe what the company stands for and how the business operates. The company scorecard recognises that people enable performance and working together as one team is an important foundation for company success. A high performing work environment is evident, and the high level of engagement and enablement has greatly assisted the business during a period of transformational growth. In July 2018 Cooper Energy conducted an employee engagement and enablement survey to calibrate the status of the company’s work environment and culture. Engagement The survey recorded an overall engagement score of 74%; a result which indicates high level of commitment, willingness to contribute additional effort and strong desire for success by the organisation. Cooper Energy’s score benchmarks favourably against international and industry results. Comparison against Korn Ferry Hay Group’s international benchmark data indicates employee engagement at Cooper Energy consistent with the international benchmark for high performing organisations and above the level recorded for the oil and gas sector and within general industry. The survey has established that, overall, people feel proud to work for Cooper Energy and have highly favourable expectations of the success of the organisation over the coming 2 to 3 years. Enablement Enablement measures the extent to which skills and abilities of people are utilised and whether the work environment supports people to perform work requirements. Cooper Energy achieved an enablement score of 70%, indicating confidence amongst staff in their ability to work effectively at Cooper Energy. The enablement score recorded for Cooper Energy aligns with Korn Ferry Hay Group’s international benchmarks for the oil and gas sector and above the general industry benchmark. Overall, the engagement and enablement survey has provided valuable insights and data on organisational strengths and opportunities. There is ongoing focus on organisational strengths and further work ahead to unlock opportunities for enhanced performance. 22 Diversity and inclusion Cooper Energy has an inclusive culture and the gender mix within the permanent workforce is 35% female and 65% male. There is female representation at all levels of the organisation. The July 2018 survey received consistent, clear and wide-ranging evidence that ‘people at Cooper Energy are given fair treatment without regard to race, colour, age, national origin and religion’. Talent and resourcing The permanent staff full time equivalent (FTE) increased by 44% from 27 persons to 39 persons during the FY18 period. The primary work locations are Adelaide and Perth. A further 75 casual and contractor staff provided support during the FY18 period. A number of external service providers continue to provide specialist services under the terms of procurement contracts. The growth in the workforce included a successful transfer of staff from Santos to Cooper Energy in July 2017 as part of the acquisition of the Victorian asset portfolio and in September 2017, the transfer of plant operators from Cooper Energy to APA Group as part of the sale of the Orbost Gas Plant. Taking time out on the helideck on the Ocean Monarch, from left: Paul Lawrence, Cooper Energy HSE Offshore Coach; Daniel Van Wanrooy, Cooper Energy Offshore Logistics Co-ordinator; Peter Bennett, Cooper Energy Senior Drilling Supervisor; and Pip Burr, Cooper Energy Drilling Supervisor Cooper Energy has a comprehensive approach to recruitment and high standards. The recruitment strategy is focussed on the hire of capable and experienced people to support organisation growth. The Managing Director and the Management Team are actively engaged in the interview process to ensure the right people with the right skills, education, experience and competency are hired and to ensure candidates are aligned with the company values. Cooper Energy’s reputation in the employment market is strong and high calibre candidates continue to express an interest in joining the organisation. In FY18, the planning phase for succession and talent management commenced. The transformational growth period has provided significant opportunity for people to grow and for people to feel a real sense of achievement which has been key to the retention of the workforce. Employee turnover for the 2018 financial year was 8%, slightly below industry and general standards. Health and wellbeing Cooper Energy has an Employee Assistance Program in place which provides professional counselling and support to assist people in dealing with the challenges of their daily work and family lives. The program, which is available to staff and contractors and their families, focusses on health and well-being and is available 24 hours a day, 7 days a week. During FY18 the program scope included onsite counselling and support on grief and loss and practical sessions for the management of stress. A Volunteer Policy provides leave opportunities for employees to make a difference in the community. A commitment to care and legacy was recognised and celebrated during the year. Accomplishments Two employees were awarded industry-based scholarships to attend the 2018 World Gas Conference held in Washington DC with a focus on “Fuelling our Future”. 23 2018 Sustainability Review Community and stakeholders Cooper Energy recognises stakeholder engagement is an ongoing process which builds relationships, enables information exchange and achieves mutually acceptable outcomes. Cooper Energy is mindful of its responsibilities to the communities in which its operations are conducted, both as a community member and through the exercise of its corporate value of care. Community and stakeholder performance Key measures Throughout the year, Cooper Energy advanced its stakeholder awareness and coverage program to align with expanded acreage across both the offshore and onshore Otway Basin regions and the Gippsland Basin. The company identified new stakeholders, including communities, businesses and government bodies and issues of relevance to the conduct of operations with which to engage and understand. Cooper Energy has adopted an open, active and timely approach to consultation and has sought to recognise the position of the stakeholder and the importance of collaboration. Ongoing initiatives are in place to ensure engagement with communities on many levels including; distribution of project flyers, coordinating stakeholder focus group and marine awareness meetings. Cooper Energy provides up-to-date information accessible via its website’s community page and expanded the company’s social media footprint to utilise platforms such as LinkedIn, Twitter and YouTube for timely and accessible sharing of announcements and activity information. Cooper Energy plans to uphold this commitment in future years, maintaining communication and the reflection of its values of awareness, transparency and integrity during planning of activities, supported by the monitoring of ongoing performance with stakeholder communities. Calibration measures for the company’s performance in community and stakeholder engagement were still to be developed at the time of printing this report. Development and implementation of metrics for community and stakeholder engagement is planned for FY19. Performance summary P Stakeholder management plan for structured communication with stakeholders in Sole Gas Project P Increased stakeholder consultation P Expanded social media footprint to allow greater transparency to operations Future focus ¢ Raising awareness and presence in local communities ¢ Development of metrics and increased monitoring of performance 24 Sunrise, offshore Victoria, looking north to Gippsland. Cooper Energy’s operations involve the company in engagement with local communities, fishing industry and recreational stakeholder groups. 25 Reserves and Resources Reserves Cooper Energy’s 2P Reserves at 30 June 2018 are assessed to be 52.4 million barrels of oil equivalent (MMboe). This is a 42.2 MMboe year-on-year increase from 30 June 2017, and a decrease of 1.7 MMboe from 2P Reserves reported on 25 August 2017 following the Sole FID update. The key factor contributing to the year-on-year revision is the declaration of the Final Investment Decision (FID) for the Sole gas project and reclassification of Sole Contingent Resources as Reserves. Reserves at 30 June 2018 Category Unit 1P (Proved) 2P (Proved and probable) 3P (Proved, Probable and Possible) Developed Undeveloped Total Developed Undeveloped 1. 1. Total Developed Undeveloped Total Sales Gas PJ Oil + Cond MMbbl Total 1, 2 MMboe 15 1.1 3.6 235 0.1 38.5 251 1.2 42.1 26 1.4 5.7 283 0.4 46.7 309 1.8 52.4 36 1.9 7.8 350 1.4 58.6 386 3.3 66.4 1. The reserves exclude Cooper Energy’s share of future fuel usage. See comment on conversion factor change in ‘Notes on Calculation of Reserves and Resources’. 2. Totals may not reflect arithmetic addition due to rounding. The method of aggregation is by arithmetic sum by category. As a result, the 1P estimate may be conservative and the 3P estimate may be optimistic due to the effects of arithmetic summation. Movement in reserves (MMboe) Category Proved (1P) Proved and Probable (2P) Proved, Probable and Possible (3P) Reserves at 30 June 2017 1 FY18 Production 2 Revisions Reserves at 30 June 2018 3 7.9 (1.5) 35.7 42.1 1. As announced to the ASX on 29 August 2017. 11.7 (1.5) 42.2 52.4 18.7 (1.5) 49.2 66.4 2. Otway Basin and Cooper Basin production from 1 July 2017 to 30 June 2018 (inclusive). The reserves exclude Cooper Energy’s share of future fuel usage. 3. Totals may not reflect arithmetic addition due to rounding. The method of aggregation is by arithmetic sum by category. As a result, the 1P estimate may be conservative and the 3P estimate may be optimistic due to the effects of arithmetic summation. See comment on conversion factor change in ‘Notes on Calculation of Reserves and Resources’. Contingent Resources Cooper Energy’s 2C Contingent Resources at 30 June 2018 have decreased since 30 June 2017 by 54.0 MMboe to a total of 23.6 MMboe. The key material factors contributing to the revision are: • Declaration in August 2017 of the Final Investment Decision (FID) for the Sole Gas Project and the company securing a fully underwritten finance package to complete funding for the project. Sole Contingent Resources therefore were reclassified as Reserves; and • Contingent Resources previously carried for the Basker field have been reclassified as Discovered Unrecoverable Resources due to approval of field abandonment. 26 Contingent Resources at 30 June 2018 Category Basin Gippsland Otway Cooper Total 1 1C (P90) Oil/Cond MMbbl Total MMboe1 1.7 0.0 0.1 1.8 12.7 2.0 0.1 14.8 Gas PJ 68 12 0 80 2C (P50) Oil/Cond MMbbl Total MMboe 1 3.2 0.0 0.1 3.4 20.4 3.1 0.1 23.6 3C (P10) Oil/Cond MMbbl 5.3 0.0 0.2 5.5 Total MMboe1 32.0 4.6 0.2 36.8 Gas PJ 165 28 0 193 Gas PJ 106 19 0 125 1. Totals may not reflect arithmetic addition due to rounding. The method of aggregation is by arithmetic sum by category. As a result, the 1C estimate may be conservative and the 3C estimate may be optimistic due to the effects of arithmetic summation. See comment on conversion factor change in ‘Notes on Calculation of Reserves and Resources’. Year-on-year movement in Contingent Resources (MMboe) Category Contingent Resources at 30 June 2017 1, 2 Revisions Contingent Resources at 30 June 2018 1, 2 1C 56.3 (41.5) 14.8 2C 77.6 (54.0) 23.6 3C 108.5 (71.7) 36.8 1. Contingent Resources at 30 June 2017 as reported to the ASX on 29 August 2017. 2. Totals may not reflect arithmetic addition due to rounding. The method of aggregation is by arithmetic sum by category. As a result, the 1C estimate may be conservative and the 3C estimate may be optimistic due to the effects of arithmetic summation. See comment on conversion factor change in ‘Notes on Calculation of Reserves and Resources’. Notes on calculation of reserves and resources Cooper Energy has completed its own estimation of Reserves and Contingent Resources for its fully-operated Gippsland Basin assets, and elsewhere based on information provided by the permit Operators (Beach Energy Ltd for PEL 92, Senex Ltd for Worrior Field; and BHP Billiton Petroleum (Vic) P/L for Minerva field); in accordance with the definitions and guidelines in the Society of Petroleum Engineers (SPE) 2018 Petroleum Resources Management System (PRMS). All Reserves and Contingent Resources figures in this document are net to Cooper Energy. Petroleum Reserves and Contingent Resources are prepared using deterministic and probabilistic methods. The 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. Totals may not exactly reflect arithmetic addition due to rounding. The company has changed the FY18 energy conversion factor consistent with Society of Petroleum Engineers (SPE) conversions and PRMS guidance. The previous conversion factor of 1 PJ = 0.172 MMboe was adopted when the company was predominantly a Cooper Basin oil producer. With the change to a predominantly offshore gas-producing company, a conversion factor of 1 PJ = 0.163 MMboe (5.8 MMBtu/bbl) is more consistent with industry and SPE standard energy conversions. The new conversion factor has no impact on gas reserves expressed in PJ. 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) and exclude reserves used for field fuel. The Cooper Basin totals comprise the arithmetically aggregated PEL 92 project fields and the arithmetic summation of the Worrior project reserves, and exclude reserves used for field fuel. The Gippsland Basin total comprises Sole gas field only, where the Contingent Resources assessment at 30 June 2017 as announced to the ASX on 29 August 2017 has been reclassified to Reserves. Contingent Resources Under the SPE PRMS 2018, “Contingent Resources are “those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable owing to one or more contingencies”. The Contingent Resources assessment includes resources in the Gippsland, Otway and Cooper basins. The following material Contingent Resources assessment was released to the ASX: • Manta field on 16 July 2015 Cooper Energy is not aware of any new information or data about Manta that materially affects the information provided in that release, and all material assumptions and technical parameters underpinning the Manta estimates provided in the release continue to apply. Basker field Contingent Resources reported on 18 August 2014 and carried unchanged through FY17 have been reclassified as Discovered Unrecoverable in FY18 due to approval of field abandonment. 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 and 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 5.41, and has consented to the inclusion of this information in the form and context in which it appears. 27 Review of Operations Production Cooper Energy’s oil and gas production for the year totaled 1.49 MMboe compared with 0.96 MMboe in the previous year. The increase is due to the twelve month contribution from gas assets in the Otway Basin acquired on 1 January 2017 and increased oil production from the Cooper Basin. Drilling The company participated in 4 wells during the year; two exploration wells in the Cooper Basin, two development wells in the Gippsland Basin and a workover of the Casino-5 well in the Otway Basin. Both of the exploration wells were plugged and abandoned. The development wells, Sole-3 and Sole-4, were both spudded prior to year-end and completed subsequently as future gas producers. Type Exploration Exploration Area Tenement Well Result Cooper Basin PRL 102 Louth-1 Cooper Basin PEL 93 Frey-1 Sole-3 Sole-4 P&A P&A Gas producer Gas producer Development Gippsland Basin VIC/L32 Development Gippsland Basin VIC/L32 Production by region MMboe 0.27 1.22 0.03 0.25 0.68 0.05 0.54 0.08 0.40 0.14 0.32 2014 2015 2016 2017 2018 Otway Basin, Australia Cooper Basin, Australia South Sumatra, Indonesia 28 ROV (remotely operated underwater vehicle) Operator at work on Ocean Monarch. 29 - a 50% interest in, and • Condensate kbbl Review of Operations Offshore Otway Basin The company’s interests in the offshore Otway Basin include: - a 50% interest in, and Operatorship of, the producing Casino Henry Netherby (“Casino Henry”) Joint Venture production licences (VIC/L24 and VIC/L30); Operatorship of, retention leases VIC/RL11 and VIC/RL12; - a 50% interest in, and Operatorship of, the VIC/P44 exploration permit; and - a 10% interest in the Minerva gas project comprising offshore production licence VIC/L22 and the Minerva Gas Plant, onshore Victoria. The plant is subject to an agreement signed by the Casino Henry joint venture participants and BHP Billiton Petroleum (Victoria) Pty Ltd for the acquisition of the Minerva Gas Plant by the joint venture participants on cessation of the current operations processing gas from Minerva. The transaction is also subject to completion of regulatory approvals and assignments. 30 Offshore Otway Basin Production Casino Henry By Project FY18 FY17 Casino Henry • Gas PJ • Condensate kbbl Minerva • Gas PJ By Product • Gas PJ • Condensate kbbl 5.73 2.98 1.31 3.20 7.04 6.18 3.28 1.96 0.75 1.70 4.03 3.66 Offshore Otway Basin 2P Reserves FY18 FY17 Developed • Gas PJ Undeveloped • Gas PJ Total • Gas PJ 26 35 61 13 43 56 The Casino Henry gas operations produce gas and gas liquids 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 metres to 71 metres. The licences are covered entirely by high- quality 3D seismic surveys acquired between 2001 and 2007. The hydrocarbon reservoirs discovered and produced to date are in the Cretaceous Waarre Formation. The depth of the top Waarre Formation at the discovered fields ranges between 1,460 metres and 2,030 metres. Casino Henry consists of a subsea development comprising four producing wells (Casino-4, Casino-5, Henry-2 and 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. Gas from Casino Henry is currently sold to Origin Energy under a contract that extends to 31 December 2018. A workover of the Casino-5 well, which had been shut in since May 2017 was completed on 25 April 2018. The workover was successful, with daily gross field production from the field increasing from the average of 26.7 TJ/day prior to an average of 33.2 TJ/ day for the balance of the financial year. Adelaide Warrnambool PEP 168 (50%) VIC/RL12 (50%) VIC/RL11 (50%) Halladale Black Watch Cooper Energy tenement Gas field Gas pipeline VICTORIA Melbourne Iona Gas Plant VIC/P44 (50%) Martha Minerva Gas Plant (10%*) VIC/P44 (50%) VIC/L30 (50%) Henry Netherby Minerva VIC/L22 (10%) Casino VIC/L24 (50%) 0 10 kilometres VIC/P44 (50%) Otway 98AR18 Undeveloped fields and exploration Permit Year 5 of the VIC/P44 exploration permit was extended to May 2019. Significant exploration potential is considered to exist in the offshore Otway acreage. Thirty-three exploration prospects have been identified, the majority of which are the same play type as current producing gas fields. The majority of the prospects are located less than 10 km from tie-in points to the existing offshore production pipeline, offering simple and close access to production infrastructure for future exploration success. Further investigation of the potential of these prospects was conducted during the year through processing of the VIC/P44 3D seismic survey to produce a Quantitative Interpretation seismic inversion volume which was integrated into other exploration studies. Several exploration prospects have been identified and work to select at least two targets for the planned offshore drilling campaign is progressing. Retention Leases VIC/RL11 and VIC/RL12 contain part of the undeveloped Black Watch gas field which has been mapped to straddle the leases and the adjoining VIC/L1(V) production licence held by Beach Energy Limited. This licence, which extends landward to the Victorian coastline, also holds the Halladale and Speculant gas fields which have been developed as onshore production operations through extended reach wells from shore. Beach Energy has announced its intention to develop the VIC/L1(V) section of Black Watch in the same manner. A production licence application for the portion of the Black Watch field located within the VIC/RL11 and VIC/RL12 tenements is being prepared for consideration by the regulator. Potential for further production increase exists through development of undeveloped reserves in the Henry gas field. The joint venture is progressing planning for a development well, as a sidetrack of Henry-2, for this purpose. It is expected the development well will be drilled as part of an offshore campaign to commence in 2019 subject to rig availability and joint venture approval. Minerva The Minerva gas field is located in production licence VIC/L22 located 9 km offshore Victoria in a water depth of 58 metres. The field was discovered by the current operator, BHP Billiton, in 2002. The project consists of two subsea development wells (Minerva-3 and Minerva-4) tied back to the Minerva Gas Plant via a 10 inch 14 km trunkline. Production from the Minerva field commenced in 2005 and has continued well beyond expectations, having surpassed the expected end-of-life in FY18. Current expectations are that production from Minerva will extend beyond FY19. Gross total field production from Minerva in FY18 averaged 35.9 TJ/day. The Minerva Gas Plant is located approximately 5 km north-west of Port Campbell. The plant, which was commissioned in January 2005, has gas processing capacity of approximately 150 TJ/day and hydrocarbon liquids processing facilities. The Minerva Gas Plant is connected directly to the SEAGas Port Campbell to Adelaide pipeline and to the South West Pipeline, owned by APA Group. 31 Review of Operations Gippsland Basin Cooper Energy’s interests in the Gippsland Basin comprise: - a 100% interest, and Operatorship of, VIC/L32 which holds the Sole gas field; Melbourne VICTORIA Orbost E A S T E R N GAS P IP E LIN E Sydney Orbost Gas Plant - a 100% interest and Operatorship of VIC/RL13, VIC/RL14 and VIC/RL15, which contain the Manta gas and liquids resource; - a 100% interest, and Operatorship of, VIC/L21, which contains the 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 permit VIC/P72, awarded in May 2018. Gippsland Basin 2P reserves FY18 FY17 Undeveloped Lakes Entrance VIC/L21 (100%) VIC/P72 (100%) Patricia-Baleen VIC/L32 (100%) Longtom Tuna Kipper Snapper Marlin Flounder Sole Sole Manta Manta Basker Chimaera Gummy VIC/RL15 (100%) Fortescue %) VIC/RL14 (100%) VIC/RL13 (100%) Kingfish Blackback Cooper Energy tenement Gas field Oil field Gas well Gas pipeline Oil pipeline 0 20 kilometres Sole pipeline; indicative Pipeline options • Gas PJ 249 - Gippsland_86AR18 32 Sole Gas Project The Sole Gas Project involves the development of the Sole gas field and upgrade of the Orbost Gas Plant to supply approximately 24 PJ per annum from July 2019. Cooper Energy is conducting the upstream component which will develop and connect the gas field. APA Group is undertaking the upgrade of the Orbost Gas Plant to process gas from Sole. The upstream project involves the drilling and connection of two near-horizontal production wells, subsea wellheads and connection of the subsea pipeline and umbilical controls to the plant via two horizontal drilled shore crossings. Work on the project commenced in the final quarter of FY17 and was taken to 56% complete at 30 June 2018. Progress to date is within schedule and budget. The completion testing and suspension of the production wells Sole-3 and Sole-4 shortly after year-end marked the fulfillment of a critical workstream in the project. Reservoir and well performance during the tests was consistent with expectations and with production capability exceeding that required by plant design. The remaining workstreams, involving the welding and installation of subsea pipeline, manufacture and installation of umbilical and connection to plant are expected to be largely accomplished in the first half of FY19, with commissioning scheduled for the final quarter of the financial year. First gas from Sole is expected to be delivered into the Orbost Gas Plant in the final quarter of FY19, on which basis first gas sales from the plant are expected from July 2019. Gas contracting The Sole gas field is assessed to hold 2P reserves of 249 PJ. Gas supply from the field is forecast to be approximately 24 PJ per annum. Approximately 170 PJ of reserves has been contracted to support funding of the project under long term sales agreements with AGL Energy, EnergyAustralia, Alinta Energy and O-I Australia. Marketing of uncontracted gas is expected to commence in FY19. Manta The Manta gas field is located in retention licences VIC/RL13, VIC/RL14 and VIC/RL15, 35 km from Sole and 58 km from the Orbost Gas Plant. The field is assessed to contain Contingent Resources (2C) of 106 PJ of gas and 3.2 MMboe of condensate. Prospective resources are also present at Manta, with a Best Estimate unrisked prospective resources of 105 MMboe comprising 526 PJ of gas, 12.9 MMbbl of condensate and 1.5 MMbbl of oil 1. The estimated quantities of petroleum that may be potentially recovered by the application of future development project(s) relate to undiscovered accumulations. These estimates have both an associated risk of discovery and a risk of development. Further exploration, appraisal and evaluation is required to determine the existence of a significant quantity of potentially moveable hydrocarbons. Manta is being considered as a follow-on development to Sole, with the capability to produce approximately 24 PJ per annum plus associated condensate. The field’s proximity to Sole and the Orbost Gas Plant enhances its prospects for development. Analysis has identified significant synergies and cost savings if Manta is developed and operated in co-ordination with Sole in areas including control umbilicals, plant, redundancies and maintenance. Provision for Manta gas to access the Orbost Gas Plant for processing has been incorporated in the agreements executed by APA Group 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 resources present in deeper reservoirs. Planning for this well, Manta-3, has progressed with the expectation the well would be drilled as part of the offshore drilling campaign being prepared to commence in the 2019 calendar year subject to rig availability. Patricia Baleen Patricia Baleen is a largely depleted offshore gas field located in production licence VIC/L21 which is in suspension and under care and maintenance after being shut-in in 2008. The field is connected to the Orbost Gas Plant by a 24 km pipeline, also owned by Cooper Energy. VIC P/72 In May the company was awarded 100% equity in offshore exploration permit VIC/ P72 for an initial six-year term. The permit adjoins the company’s VIC/L21 production licence which holds the depleted Patricia- Baleen gas field and its associated subsea production infrastructure connected to the Orbost Gas Plant. VIC/P72 is 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 similar 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. 1. As announced to ASX on 4 May 2016. Cooper Energy confirms that it is not aware of any new information or data that materially affects the resource estimate information included in the announcements and that all the material assumptions and technical parameters underpinning the estimates in the announcements continue to apply and have not materially changed. 33 Review of Operations Onshore Cooper Basin Cooper Energy holds interests in three exploration licences, 28 retention licences and eleven production licences in the South Australian Cooper Basin. The company’s activities are primarily focussed on tenements held by the PEL 92 Joint Venture (‘PEL 92‘) on the western flank of the basin, which provided approximately 26% of Cooper Energy’s total production in FY18. The Worrior Field (PPL 207) supplied 2% of Cooper Energy’s total production for the year. Onshore Otway Basin Cooper Energy holds interests in four exploration licences and one retention licence in the onshore Otway Basin, covering a total area of 7,292 km2: - a 30% interest in PEL 494 and PRL 32, Penola Trough, South Australia; - a 20% interest in PEP 150, Victoria. Since year-end, this interest increased to 50% following Beach Energy’s withdrawal from this permit and government approval and registration of the transfer; - a 25% interest in PEP 171, Penola Trough, Victoria. Since year-end, this interest has increased to 100% 34 2018 operations The company’s share of oil production from the Cooper Basin during the year was 270,000 barrels, 96% of which was from the PEL 92 Joint Venture. Production for the 12 months to 30 June was 8% higher than the previous year, an outcome which reflects the benefits of development well drilling conducted in FY17 and reported in the previous annual report. Two exploration wells were drilled in the company’s Cooper Basin acreage during the year: Louth-1 in PRL 102 and Frey-1 in PEL 93. Both wells were plugged and abandoned. Joint venture and tenement interests 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; - a 30% interest in PEL 93 and PPL 207 which holds the producing Worrior oil field; - a 25% interest in PEL 90K; - a 19.17% interest in the PRL’s 207-209 (ex PEL-100), and - a 20% interest in the PRL’s 183- 190 (ex PEL-110). following Beach Energy’s withdrawal from this permit and government approval and registration of the transfer. Cooper Energy’s interest may reduce by up to 50% on fulfillment of farm-in arrangements executed with Vintage Energy Ltd during the year; and - a 50% interest in PEP 168, Victoria. Exploration The company’s primary focus in the onshore Otway Basin is exploration of gas plays associated with the Casterton, Sawpit and Pretty Hill formations, primarily within the Penola Trough. Analysis of data from Jolly-1 ST1 and Bungaloo-1 drilled in 2014 has assisted identification of a number of opportunities for future evaluation of the deep plays in the Penola Trough. The potential of this play was proven during the year by the new gas field discovery made by the Haselgrove-3 sidetrack well drilled by Beach Energy in PPL 62, a licence surrounded by PEL 494. During the year the PEL 494 joint venture was awarded a PACE Gas Round 2 grant by the South Australian Government of $6.89 million to drill the Dombey prospect. Dombey-1 will test the Pretty Hill sandstone and the deeper Sawpit sandstone where gas was discovered at Haselgrove and is scheduled to be drilled during the 2019 financial year. Activity in the Victorian permits has been suspended pursuant to the moratorium imposed by the state government on onshore petroleum exploration and production until 30 June 2020. 139°3 139° 140° Plan area PRLs 183-190 (20%) (former PEL 110) -27°2 -27° TAS -27° Cooper Energy tenement Other companies’ tenement Oil field Gas field Oil pipeline Gas pipeline PRLs 207-209 (19.165%) (former PEL 100) e r m ia n edge C oop er C r P PEL 90K (25%) R O U G H Rincon North Rincon PRLs 85 to 104 (25%) (former PEL 92) A H P A T C Callawonga Elliston Windmill Christies Sellicks Silver Sands -28° Parsons Perlubie Germein Butlers Lycium Hub PRL 231 (30%) (former PEL 93) PRL 232 (30%) (former PEL 93) PRL 233 (30%) (former PEL 93) Worrior PPL 207 PRL 237 (30%) (former PEL 93) 0 20 40 139° kilometres an edge i m r e P 140° Kingston SE SOUTH AUSTRALIA Naracoorte PEL 494 (30%) PRL 32 (30%) ROBE TROUGH Robe ST CLAIR TROUGH Beachport A T e e k R R A W MI R I D G E G E M A P P A N G U O R MOOMBA A T G N U L L A R O U G H R I T -28° R H H G U O R A T R E P P A N E T Cooper 83AR18 Cooper Energy tenement Gas field Gas pipeline Depositional trough PE N O LA Millicent Penola Katnook Nangwarry T R O U G H M Mount Gambier PEP 171 (100%*) VICTORIA ARDONAC HIE T R O U G H Hamilton PEP 150 (50%) PEP 168 (50%) Cobden Portland Warrnambool Plan area 0 20 40 TAS kilometres SHIPWRECK TROUGH Otway 97AR18 Otway 97AR18 n i s a B r e p o o C t n i s a B y a w O e r o h s n O 35 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 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) PEL 90 (Kiwi sub-block) PRLs 85-104 PRLs 231-233 and 237 1 25% 30% 25% 25% 25% 25% 25% Onshore Onshore Onshore Onshore Onshore Onshore Onshore 25% Onshore 25% 25% 25% 25% 30% Onshore Onshore Onshore Onshore Onshore PRLs 207-209 19.17% Onshore PRLs 183-190 20% Onshore 2.0 4.3 6.4 5.5 1.8 2.1 0.1 1.5 2.0 0.8 0.6 Beach Energy Production 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 144.6 Senex Energy Exploration 1889.3 Beach Energy Exploration 621.8 296.5 727.5 Senex Energy Exploration Senex Energy Exploration Senex Energy Exploration 1. PRL 237 is subject to a Farmin Agreement which could reduce Cooper Energy’s interest to 20%. Gippsland Basin State Victoria Tenement VIC/L21 VIC/RL13 VIC/RL14 VIC/RL15 VIC/L32 Interest Location Area (km2) Operator Activities 100% Offshore 134.0 Cooper Energy Production (suspended) 100% 100% 100% 100% Offshore Offshore Offshore Offshore 67.0 67.0 67.0 Cooper Energy Retention Cooper Energy Retention Cooper Energy Retention 201.0 Cooper Energy Development (for Sole Gas Project) VIC/P72 100% Offshore 269.0 Cooper Energy Exploration 36 Otway Basin State Tenement Interest Location Area (km2) Operator Activities South Australia PEL 494 Victoria PRL 32 VIC/L22 VIC/L24 VIC/L30 VIC/RL11 VIC/RL12 VIC/P44 PEP 150 PEP 168 PEP 171 30% 30% 10% 50% 50% 50% 50% 50% 50% 50% Onshore Onshore Offshore Offshore Offshore Offshore Offshore Offshore Onshore Onshore 2,488.8 Beach Energy Exploration 36.9 58.0 199.0 200.0 Beach Energy Exploration BHP Production Cooper Energy Production Cooper Energy Production 127.0 Cooper Energy Retention 6.0 Cooper Energy Retention 599.0 Cooper Energy Exploration 3,212.0 Bridgeport Exploration 795.0 Beach Energy Exploration 100%1 Onshore 1,974.0 Cooper Energy Exploration 1. Subject to Heads of Agreement for a farmin which could reduce Cooper Energy’s interest by up to 50%. Rig support vessel Far Senator viewed from Ocean Monarch. Support vessels were one of a number of services required to support the offshore campaign. Other services included helicopter, shore base logistics, fuel supply, specialist drilling contractors, catering and transportation services. 37 Board of Directors 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 Ms Elizabeth A. Donaghey B.Sc., M.Sc. Appointed 25 June 2018 Experience and expertise Experience and expertise Experience and expertise Mr Conde has extensive experience in business and commerce and in chairing high profile business, arts and sporting organisations. 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) and the Sydney Symphony Orchestra (2007 – 2015) and is a former Director of AFC Asian Cup (2015) (2012 – 2015). Previous positions include Non-Executive Director of BHP Billiton, Chairman of Pacific Power (the Electricity Commission of NSW), Chairman of Events NSW, President of the National Heart Foundation and Chairman of the Pymble Ladies’ College Council. Special responsibilities Mr Conde is Chairman of the Board of Directors. He is also a member of the Remuneration and Nomination Committee. 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 Ltd. Special responsibilities Mr Maxwell is Managing Director and is responsible for the day to day leadership of Cooper Energy. He is the leader of the management team. Mr Maxwell is also chair of the HSEC Committee (a management committee, not a Board committee). 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 Australian Energy Market Operator (AEMO) (since 2017), Ms Donaghey is a former Director of Imdex Ltd (2009 - 2016), St Barbara Limited (2011 - 2014) and Australian Renewable Energy Agency (2012 - 2014) Special responsibilities Ms Donaghey does not currently hold any Committee roles. 38 Non-Executive Director Mr Hector M. Gordon B.Sc. (Hons). FAICD Appointed 24 June 2017 Executive Director 26 June 2012 – 23 June 2017 Independent Non-Executive Director Mr Jeffrey W. Schneider B.Com Appointed 12 October 2011 Independent Non-Executive Director Ms Alice J. M. Williams B.Com FAICD, FCPA, CFA Appointed 28 August 2013 Experience and expertise Experience and expertise 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 is a former Director of Comet Ridge Limited ASX: COI (2003 – 2014). Special responsibilities Mr Schneider is Chairman of the Remuneration and Nomination Committee and a member of both the Risk and Sustainability Committee and the Audit Committee. Mr Gordon is a very successful geologist with over 40 years of experience in the petroleum industry. 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. Mr. Gordon’s previous employers also include Santos Limited, AGL Petroleum, TMOC Resources, Esso Australia and Delhi Petroleum Pty Ltd. Current and other directorships in the last 3 years Mr Gordon is a Director of Bass Oil Limited ASX: BAS (since 2014) and various wholly owned subsidiaries of Cooper Energy Limited. Special responsibilities Mr Gordon is the Chairman of the Risk and Sustainability Committee and a member of the Audit Committee. 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, Telstra Sale Company, V/Line Passenger Corporation, State Trustees, Western Health and the Australian Accounting Standards Board. 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, Victorian Funds Management Corporation (since 2008), Barristers Chambers Ltd (since 2015), the Foreign Investment Review Board (since 2015), Defence Health (since 2010) and not for profit Tobacco Free Portfolios (since 2018). Ms Williams is a former council member of the Cancer Council of Victoria and former Non-executive Director of Guild Group and Port of Melbourne Corporation. Special responsibilities Ms Williams is the Chairman of the Audit Committee and a member of both the Risk and Sustainability Committee and the Remuneration and Nomination Committee. 39 Executive Management Team Managing Director David Maxwell M. Tech FAICD General Manager, Development Duncan Clegg PhD – Soil Mechanics, BSc Engineering Company Secretary and Legal Counsel Alison Evans B.A., LLB General Manager, Commercial and Business Development Eddy Glavas B.Acc CPA, MBA Ms Evans was appointed to the position of Company Secretary and Legal Counsel on 25 February 2013. Ms Evans is an experienced company secretary and corporate legal counsel with extensive knowledge of corporate and commercial law in the resources and energy sectors. Ms Evans has been Company Secretary and/or Legal Counsel in a number of minerals and energy companies including Centrex Metals, GTL Energy and AGL. Ms Evans’ public company experience is supported by her work at leading corporate law firms. Mr Glavas joined Cooper Energy in August 2014 with more than 16 years’ experience in business development, finance, commercial, portfolio management and strategy, including 12 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&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. 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. As Senior Vice President at QGC - a BG Group business – he was responsible for all commercial, exploration, business development, strategy and marketing activities. He led BG Group’s entry into Australia, its involvement in the alliance with Queensland Gas Company Limited and its subsequent takeover by BG Group. Mr Maxwell was previously director of gas and marketing with Woodside in Perth and a member of Woodside’s executive committee. He has served on a number of industry association boards, government advisory groups and public company boards and is a recipient of the Australian Gas Association Silver Flame Award for his contribution to the gas industry. Mr Clegg has extensive experience in upstream and midstream oil and gas development acquired over 35 years, including senior management positions at Shell and Woodside. His experience features leadership roles in the North Sea, Africa and Malaysia, the management of gas receiving facilities and LNG plant expansions at Bintulu (Malaysia) and the North West Shelf and FPSO, subsea and fixed platforms developments. Mr Clegg held several senior executive positions at Woodside including Director of the Australia Business Unit, Director of the Africa Business Unit and CEO of the North West Shelf Venture. Prior to joining Cooper Energy he managed the development and projects group at Coogee Resources and worked as an independant consultant on a range of offshore oil and gas project developments including FLNG with Höegh LNG. Mr Clegg was a board member of Verve Energy from 2011 to 2013 and of Matrix Composites Limited from 2014 to 2017. 40 General Manager, Projects Michael Jacobsen B. Eng (Hons) Mr Jacobsen has over 25 years experience in upstream oil and gas specialising in major capital works projects and field developments. He has worked more than 10 years with engineering and construction contractors and then progressed to managing multi discipline teams on major capital projects for E&P companies. Mr Jacobsen is the Project Manager for the Sole GasProject from the commencement of FEED. General Manager, Operations 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 20 years’ experience in finance and accounting and secretarial roles, including 18 years in publicly listed entities, principally in group finance and secreterial roles in the resources and media sectors. This has included the role of 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, culminating in performance of the role of 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. Following the takeover, he was COO at Bight Petroleum, a privately held independent exploration company and was a Director of Barker Wentworth, a specialist oil and gas consulting company. 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 also 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. 41 Key Performance Indicators Operational Production 12 months to 30 June MMboe Proved and probable reserves MMboe Wells drilled number Exploration wells spudded number 2010 2011 2012 2013 2014 2015 2016 2017 2018 0.47 2.00 4 4 0.41 2.47 12 6 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 Reserve replacement ratio1 percent 11% 134% -113% 98% 71% 333% 18% 768% 2,380% 4.7 9.1 21.0 8.4 61.5 13.2 53.4 22.5 37.0 Financial Sales revenue Other revenue EBITDA Profit before tax Profit after tax / (loss) $ million 40.0 39.1 59.6 53.4 72.3 39.1 27.4 39.1 $ million $ million $ million $ million 4.3 8.0 7.2 1.2 5.1 (6.0) (5.5) (10.3) 2.3 22.3 18.3 2.8 1.9 0.9 36.9 (58.4) (37.4) 1.6 1.9 31.2 (18.8) (26.0) (7.0) 1.3 22.0 (63.5) (34.8) (12.3) 67.5 4.9 49.9 31.0 27.0 Cash and term deposits $ million 92.5 72.4 Other financial assets Working capital Accumulated profit $ million $ million $ million Cumulative franking credits $ million - 95.4 24.4 25.7 - 79.5 14.1 31.4 47.9 20.2 51.7 23.8 39.0 49.1 26.0 41.2 39.4 49.8 147.5 236.9 1.9 1.0 0.7 42.6 43.0 44.2 84.0 154.0 45.7 (17.7) (52.6) (64.9) (37.9) 38.7 43.7 42.9 42.9 42.9 Shareholders equity $ million 125.1 114.9 136.9 137.2 167.8 103.9 91.6 285.0 443.9 Earnings per share cents 0.4 (3.5) 2.8 0.4 6.4 (19.2) (10.1) (1.8) 1.8 Return on shareholders funds percent 1.0% -8.6% 6.7% 0.9% 14.4% -46.7% (-38.0)% -6.5% 7.4% Total shareholder return percent (17.8)% (2.7)% 25.0% (16.7)% 34.7% (51.5)% (12.2)% 72.7 6.0% Average oil price A$/bbl 87.02 95.42 114.63 112.31 124.08 85.48 60.75 61.89 99.61 Capital as at 30 June Share price Issued shares $ per share 0.37 0.36 0.45 0.375 0.505 0.245 0.215 0.38 0.385 million 292.6 292.6 327.3 329.1 329.2 331.9 435.2 1,140.2 1,601.1 Market capitalisation $ million 108.3 105.3 147.3 123.4 166.3 81.4 93.6 433.3 616.4 Shareholders number 6,537 5,573 5,485 5,284 5,122 5,103 4,931 6,292 6,622 1. Reserve replacement ratio calculated by net IP reserve addition/production. 42  Cooper Energy Limited and its controlled entities Financial Report For the year ended 30 June 2018 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 Financial Statements 1 Corporate information 2 3 4 5 Summary of significant accounting policies Segment reporting Revenues and expenses Income tax 6 Discontinued operations and assets held for sale 7 Earnings per share 8 Cash and cash equivalents and term deposits 9 Trade and other receivables 10 Prepayments 11 Equity instruments 12 Oil and gas assets 13 Impairment 14 Property, plant and equipment 15 Exploration and evaluation 16 Trade and other payables 17 Provisions 18 Interests in joint arrangements 19 Contributed equity and reserves 20 Financial risk management objectives and policies 21 Hedge accounting 22 Commitments and contingencies 23 Interests in joint arrangements 24 Related parties 25 Share based payment plans 26 Auditors remuneration 27 Parent entity information 28 Events after the reporting period Directors’ Declaration Independent Audit Report Auditors’ Independence Declaration Abbreviations and terms 44 54 56 74 75 76 77 78 78 91 94 95 97 98 99 100 100 100 101 101 101 102 102 102 104 104 106 110 111 112 112 114 116 116 116 117 118 126 127 Corporate Directory Inside back cover 4343 Operating and Financial Review For the year ended 30 June 2018 Summary Overview The Company’s financial accounts for the twelve months to 30 June (“the year” “2018 financial year” or “FY18”) are the first to report a full twelve-month performance since the Victorian gas asset acquisition completed in the prior year. Significant changes in the entity’s structure Two features of the results are particularly noteworthy: the scale of growth in the Company and its financial and operating results; and the value added by the technical, commercial and financing activities undertaken during the year. The most significant example of the latter was the Final Investment Decision (“FID”) for the Sole Gas Project on 29 August. Gas contracting, workover results and project performance were other sources of significant value creation during FY18. Cooper Energy’s position at year end was one from which further growth in scale and value is expected to be achieved. The Sole Gas Project has advanced consistent with schedule and budget; new gas contracts are in the midst of negotiation; and planning has commenced on a range of development, appraisal and exploration projects expected to be undertaken within 18 to 24 months. Operations Cooper Energy generates revenue from the supply of gas to south-east Australia and oil production in the Cooper Basin. The Company’s current operations and interests include: • offshore gas and gas liquids production in the Otway Basin, Victoria, from the Casino Henry and Minerva Gas Projects; • the Sole Gas Project under development in the offshore Gippsland Basin; • the Manta gas and liquids resource in the offshore Gippsland Basin; • onshore oil production and exploration from the western flank of the Cooper Basin; • gas exploration in the offshore and onshore Otway Basin; and • offshore gas exploration in the Gippsland Basin. The Company is the Operator for offshore gas production and exploration in the Otway Basin and offshore gas exploration and development in the Gippsland Basin. Reserves and contingent resources Proved and probable reserves at 30 June were 52.4 million boe (barrels of oil equivalent) compared with 11.7 million boe at the beginning of the period. Contingent resources (2C) were 23.6 million boe compared with 77.6 million boe. The reclassification of 42.7 million boe of gas in the Sole gas field from contingent resources (2C) to proved and probable (2P) reserves was the major factor in the movement in reserves and resources. Proved and probable reserves comprise 309.5 PJ of gas and 1.9 million barrels of oil. Workforce At 30 June 2018 the Company had 38.9 full time equivalent (FTE) employees and 62.1 FTE contractors compared with 26.9 FTE employees and 14.1 FTE contractors at 30 June 2017. The increase in employee numbers is consistent with the development of the Company’s scale and responsibilities. Contractor numbers increased due to resourcing for the Sole Gas Project, in particular the offshore drilling campaign that commenced in March 2018. Health Safety Environment and Community The Company submitted, and received regulatory acceptance for environmental management plans and safety cases in respect of Victorian gas assets acquired in January 2017 for which the Company now has Operator responsibility. These include the Casino Henry Gas Project, Sole Gas Project and VIC/P44. Zero recordable cases or reportable environmental incidents occurred within Cooper Energy operations during the 12 months to 30 June 2018. No lost time incidents were recorded and there were two restricted work case incidents. Production Production for the year of 1.49 million boe compares to 0.97 million boe in FY17. The movement against the previous year incorporates: • the contribution of a full year’s gas production of 7.04 PJ from Otway Basin gas assets, which contributed six month’s production of 4.03 PJ to the prior year results. These assets also contributed 6.2 thousand barrels of condensate compared to 3.7 thousand barrels for the 6-month period from acquisition in FY17; • increased crude oil production from the Cooper Basin. Oil produced by the Company’s interests in the western flank of the Cooper Basin was 0.27 million barrels, 8% higher than the previous year’s production of 0.25 million barrels; and • offset by oil production of 25.9 thousand barrels in FY17 from Indonesian assets divested in that year. 44 Operating and Financial Review For the year ended 30 June 2018 Operations continued Commercial The Company’s strategy for the creation of shareholder value involves the establishment and operation of a portfolio style gas business to address supply opportunities in south-east Australia, supported by low cost oil operations. Commercial activities in the period from 2012 to 2017 were directed towards building an asset portfolio capable of generating value from the supply opportunities foreseen. With a core portfolio in place by 2017, the focus of commercial activities in 2018 shifted to gas contracting and the acquisition of assets which add value to the Company or to other assets already held. In December 2017 the Company agreed a new gas supply contract with Origin Energy Limited for the supply of gas from Casino Henry for the period 1 March 2018 to 31 December 2018. The contract is the first new sales agreement for the project since it commenced supply in 2006 and has realigned prices for gas supplied from Casino Henry to current market levels. Negotiation of new sales agreements to operate from 1 January 2019 are progressing. Gas from Casino Henry is processed at the Iona Gas Plant under an agreement with Lochard Energy with matching duration to the gas supply contract. In addition, the signing of an agreement with BHP Petroleum during the year to acquire the Minerva Gas Plant provides the Casino Henry joint venture with a competitive longer-term alternative supply option which also holds strategic value as a hub for broader Otway Basin gas development. Exploration and development Otway Basin, offshore The Company holds offshore and onshore interests in the Otway Basin. Offshore interests comprise: a) a 50% interest in, and Operatorship of, the producing Casino Henry Netherby (“Casino Henry”) Production Licences (VIC/L24 and VIC/L30); b) a 50% interest in, and Operatorship of, Retention Licences VIC/RL11 and VIC/RL12; c) a 50% interest in, and Operatorship of, Exploration Permit VIC/P44; and d) a 10% interest in the Minerva Gas Project comprising the offshore licence VIC/L22 and the Minerva Gas Plant, onshore Victoria. Exploration Exploration activities in relation to VIC/P44 included a review of exploration potential. Processing of the VIC/P44 3D seismic survey was conducted and seismic reprocessing completed and integrated into other exploration studies. The work identified several exploration prospects, located in good proximity to pipelines, considered to hold potential to be economic gas discoveries. Work is proceeding on the selection of up to 2 targets for drilling in an offshore drilling campaign proposed for FY20. Development The Casino Henry Joint Venture conducted a workover of the Casino-5 well, which had been shut-in since May 2017. The workover was successful and Casino-5 returned to service in April 2018 with daily gross production from Casino Henry increasing from 26.7 TJ/day averaged in the March quarter to average 33.2 TJ/day for the balance of the financial year. Planning and analysis commenced for the drilling of a development well to access the undeveloped reserves of the Henry field. It is expected the well, most likely a sidetrack of the existing Henry-2 well, will be drilled in the December quarter 2019, subject to joint venture approval and rig availability. Otway Basin, onshore Onshore Otway Basin interests are located in the states of South Australia and Victoria. In South Australia, the Company holds a 30% interest in each of PEL 494 and PRL 32, the balancing interests and operatorship of both blocks are held by Beach Energy Limited. The licences are adjacent to PPL 62 which contains the Haselgrove gas discovery announced by Beach Energy Limited during the year. Activity in the Victorian onshore Otway Basin is currently in suspension pursuant to the moratorium imposed by the Victorian state government on onshore exploration until June 2020. Interests held in the Victorian Otway Basin include PEP 168 (50%), PEP 150 (currently 20%, increasing to 50% pending government ratification) and PEP 171 (currently 25% increasing to 100% on pending government ratification). 45 Operating and Financial Review For the year ended 30 June 2018 Operations continued Gippsland Basin Commercialisation of the Company’s gas resources in the Gippsland Basin is a principal element of the Company’s growth strategy. The Company’s interests in the region comprise: a) a 100% interest in, and Operatorship of, Production Licence VIC/L32 which holds the Sole gas field; b) a 100 % interest in, and Operatorship of, Retention Licences VIC/RL13, VIC/RL14 and VIC/RL15, which hold the Manta gas field. Manta is assessed to contain contingent resources (2C) of 106 PJ1 of gas and 3.2 MMbbl of liquids as well as hydrocarbon potential in deeper reservoirs. The retention leases also hold legacy oil infrastructure associated with the disused BMG oil project; c) a 100% interest in, and Operatorship of, Retention Licence VIC/RL22 which contains the largely depleted and shut-in Patricia-Baleen gas field, and infrastructure offering connection to the Orbost Gas Plant; and d) a 100% interest in Exploration Permit VIC/P72 awarded in May 2018. The Company is pursuing a two-phase development program of its Gippsland gas resources involving development of Sole to supply gas from 2019 and a subsequent development of Manta. Sole Gas Project The Sole Gas Project is being undertaken to develop the Sole gas field, offshore Victoria, for supply to commence mid-2019. The project has a budget total capital cost of $605 million, comprising a $355 million offshore development to be conducted by Cooper Energy and the $250 million upgrade of the existing Orbost Gas Plant by APA Group. Sole is being developed by the drilling and completion of two production wells, installation and connection of subsea wellheads and infrastructure to the Orbost Gas Plant via 65 kilometres of pipe, a control umbilical and horizontally directional drilled (HDD) shore crossing. Offshore project FID occurred on 29 August 2017. At 30 June the offshore project was proceeding within schedule and budget having reached 56% complete with incurred capital expenditure by Cooper Energy of $189 million. Project milestones completed include the twin horizontal directional drilled shore crossing for the pipeline and umbilical and, after year end, the drilling, and completion of the Sole-3 and Sole-4 production wells, inclusive of subsea wellhead installation. Welding of the pipeline is underway and advancing towards readiness for the installation commencement in October 2018. The umbilical has been manufactured in the UK and is having end fittings applied prior to testing. Installation of the umbilical is expected to be performed between November 2018 and January 2019. The completion of the production wells in August 2018 marked a major milestone for the offshore project, establishing well production performance exceeding plant design requirements and gas composition and reservoir characteristics in line with Sole-2 and expectations. Manta Gas Project Development of the Manta gas and liquids field is being pursued as a second phase Gippsland gas development, utilising economies available through coordination with the Sole Gas Project. A formal business case conducted in 2015 found that commercialisation of the gas field could be feasible. Appraisal of the field’s contingent resources is considered necessary for confirmation of the assessed contingent resource. It is intended that this well, Manta-3, will also test the potential of a prospective resource in deeper reservoirs. The results of Manta-3 will inform a development decision on the field and the final firm development plan. Current expectations are that Manta-3 will be drilled in the offshore drilling campaign being planned for FY20. Based on the current contingent resource, the Manta development concept is expected to involve subsea wellheads for the production of gas and gas liquids through connection to the Orbost Gas Plant by either a direct pipeline or via connection to the Patricia-Baleen gas field and pipeline. Cooper Basin Interests in the Cooper Basin include a 25% interest in the oil producing PEL 92 Joint Venture (PRL’s 85 – 104) and a 30% interest in the PPL 207 Joint Venture and their associated petroleum retention licences. The Company participated in two exploration wells during the period, one by each joint venture, which were both plugged and abandoned after failing to encounter significant hydrocarbons. The Company also holds interests in exploration licences in the northern Cooper Basin. There were no other exploration or development activities of significance in the Company’s Cooper Basin acreage during the year. 1 Cooper Energy announced contingent and prospective resource attributable to Manta on 16 July 2015. Cooper Energy is not aware of any new information or data that materially affects the information provided in those releases and all material assumptions and technical parameters underpinning the assessment provided in the announcement continues to apply. 46 Operating and Financial Review For the year ended 30 June 2018 Financial Performance Cooper Energy recorded a statutory profit after tax of $27.0 million for the financial year which compares with the loss after tax of $12.3 million recorded in the 2017 financial year. The 2018 financial year profit included a number of items which affected the result by a total of $17.2 million. These items comprise: • a gain on sale of the Orbost Gas Plant of $21.9 million; • a non-cash restoration expense of $4.9 million resulting from a remeasurement of the Patricia Baleen Field rehabilitation provision; • impairment losses recognised in respect of the Group’s Cooper Basin northern licenses of $0.5 million net of tax impacts; • a gain on the movement in the consideration receivable from the sale in the prior year of Sukananti of $0.5 million; • a gain on the derecognition of the Group’s investment in an associate of $0.4 million; and • a loss on the movement in the Hammamet exit provision of $0.2 million. Financial Performance Sales volume Sales revenue Gross profit Gross profit / Sales revenue Operating cash flow Cash, other financial assets and investments Reported NPAT/(loss) after tax Underlying NPAT/(loss) after tax Underlying profit/(loss) before tax Underlying EBITDA* MMboe $ million $ million % $ million $ million $ million $ million $ million $ million FY18 1.482 67.5 29.0 43.0 22.2 259.3 27.0 9.8 14.0 32.6 FY17 0.951 39.1 16.6 42.5 4.1 148.2 (12.3) (8.7) (5.8) 5.3 Change 0.531 28.4 12.4 0.5 18.1 111.1 39.3 18.5 19.8 27.3 % 56% 73% 75% 1% 441% 75% 320% 213% 341% 515% * Earnings before interest, tax, depreciation and amortisation Note the comparative numbers in the table above include discontinued operations. 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. Calculation of underlying NPAT / (loss) by adjusting for items unrelated to the underlying operating performance is considered to provide meaningful comparison of results between periods. Underlying NPAT / (loss) and underlying EBITDA are not defined measures under International Financial Reporting Standards and are not audited. Reconciliations of NPAT / (loss), Underlying NPAT / (loss), Underlying EBITDA and other measures included in this report to the Financial Statements are included at the end of this review. The underlying profit after tax (exclusive of the items noted above) was $9.8 million, compared with an underlying loss after tax of $8.7 million in the 2017 financial year. The factors which contributed to the movement between the periods were: • higher gas sales revenue of $21.9 million as a result of a full year of revenue from the assets acquired during the 2017 financial year; • higher oil sales revenue of $6.5 million as a result of increased oil price realised throughout the period and increased volumes, partially offset by the sale of the Company’s Indonesian producing assets in the 2017 financial year; • higher interest revenue of $2.8 million as a result of higher cash balances; • higher production costs of $6.2 million as a result of the Victorian gas assets and increased Cooper Basin production; • higher amortisation costs of $9.7 million, mainly due to amortisation on gas assets acquired; • lower administration and other costs of $3.8 million, mainly relating to higher cost recoveries associated with increased activities on operated projects; • higher non-cash finance costs and restoration expenses of $0.2 million, as a result of accretion relating to rehabilitation provisions associated with the assets acquired during the 2017 financial year; and • higher tax expense of $1.2 million mainly in respect of PRRT relating to the Company’s producing gas assets. 47 Operating and Financial Review For the year ended 30 June 2018 Financial Position Financial Position Total assets Total liabilities Total equity Assets $ million $ million $ million FY18 816.8 372.9 443.9 FY17 492.6 207.6 285.0 Change 324.2 165.3 158.9 % 66% 80% 56% Total assets increased by $324.2 million from $492.6 million to $816.8 million. At 30 June the Company held cash and deposit balances of $236.9 million, other financial assets of $20.1 million, investments of $2.2 million and drawn debt of $125.9 million. Cash and deposit balances increased by $89.4 million over the period as summarised in the chart below. Operating activities produced $22.2 million of cash flows, including: • cash generated from operations of $46.1 million; • interest revenue of $3.8 million; • general administration costs of $8.6 million; • restoration costs of $12.4 million; • petroleum resource rent tax (“PRRT”) payments of $6.7 million. Financing and investing cash flows included: • net proceeds from equity issues of $127.2 million; • debt drawdowns of $113.6 million (net of costs of $12.3 million); • restoration proceeds from exited parties of $48.1 million; • interest payments of $4.6 million; • exploration and development costs of $198.5 million; • acquisitions of oil and gas assets of $21.0 million consisting of contingent consideration of $20.0 million paid to Santos Limited on the FID decision on the Sole Gas Project and $1.0 million in respect of the Minerva Plant acquisition; • receipts from the disposal of producing assets of $0.7 million; • receipts from sale of the Orbost Gas Plant of $41.9 million; and • transfers of cash to escrow accounts of $40.2 million. 48 Operating and Financial Review For the year ended 30 June 2018 Financial Position continued $ million Total cash, other financial assets and investments 148.2 -4.6 +48.1 +113.6 -198.5 Total cash, other financial assets and investments 259.3 +127.2 -21.0 +0.7 +41.9 -40.2 22.4 Other financial assets and investments Other financial assets and investments 0.7 -8.6 -12.4 +46.1 +3.8 -6.7 Cash & deposits 147.5 169.7 236.9 Cash & deposits Operating +22.2 Other +67.2 June -17 Operations General Admin Restoration costs PRRT Interest Cash after operating cash flows Net debt draw- downs Net proceeds from equity issues Restoration proceeds Interest payments E & D Acquisitions of oil & gas assets Transfer to escrow June-18 Receipts from disposal of producing asset Receipts from disposal of PPE Exploration and evaluation assets decreased $124.6 million from $223.3 million to $98.7 million as a result of transferring the carrying amount of the Sole asset from exploration to oil and gas properties on FID partially offset by capital expenditure incurred on exploration activities. Oil and gas assets increased by $325.2 million from $69.4 million to $394.6 million mainly as a result of transferring the Sole asset on FID (as mentioned above) and capital expenditure incurred on the project after FID partially offset by amortisation charges. Total Liabilities Total liabilities increased by $165.3 million from $207.6 million to $372.9 million. Provisions increased by $61.5 million from $119.0 million to $180.5 million attributable to the assumption of increased rehabilitation provisions for BMG on settling with exited parties and the recognition of provisions associated with the drilling of Sole-3 and Sole-4. Interest bearing loans and borrowings increased to $116.9 million from a nil balance in the 2017 financial year. This represents the drawdowns under the reserve-based lending (RBL) facility of $125.9 million offset by associated capitalised transaction costs of $8.9 million. Total Equity Total equity has increased by $158.9 million from $285.0 million to $443.9 million. In comparing equity at June 2018 to June 2017 the key movements were: • higher contributed equity of $128.7 million due to shares issued from equity raisings and shares issued on vesting of performance rights during the period; • higher reserves of $3.2 million mainly due to the issue of equity incentives to employees partially offset by fair value movements in the Company’s oil price options and interest rate swaps for which cash flow hedge relationships apply; and • lower accumulated losses of $27.0 million due to the reported profit for the period. 49 Operating and Financial Review For the year ended 30 June 2018 Business Strategies and Prospects As noted under ‘Commercial’ above, the core element of the Company’s strategy for the generation of shareholder wealth is the operation of a portfolio of gas assets with superior competitiveness in the supply of gas to south-east Australia. The foundation for this strategy’s success is value- adding acquisition, discovery, development, contracting and supply of gas. At 30 June 2018, Cooper Energy occupied a position from which growth in shareholder value is expected. The passage of the Sole Gas Project has the Company on schedule to increase gas sales from 6 PJ per annum (“p.a.”) to approximately 30 PJ p.a. within 2 years. The Company holds uncontracted 2P gas reserves of some 127 PJ, which are competitively located and will be marketed into south-east Australia where forecast demand is expected to exceed local production for the foreseeable future. The Company’s portfolio holds the potential to add more gas reserves through commercialisation of contingent resources present in the Manta gas field and the exploration drilling of prospects identified in the offshore and onshore Otway basins. Cooper Basin oil operations are expected to continue to generate cash from low cost, high margin oil production. Acquisition opportunities will be assessed for their capacity to generate value for shareholders, subject to the Company’s stated key investment criteria: 1) the assets are cost competitive; 2) there is a foreseeable pathway to commercialisation within 5 years; and 3) the opportunity offers the potential for value creation; whether that be an incremental increase to the value of the assets through the application of Cooper Energy’s capabilities and/or an incremental increase to the value of Cooper Energy’s portfolio arising from integration of the assets. Outlook FY19 is expected to be a year of consolidation as the Sole Gas Project is completed and preparations made for an offshore drilling campaign to commence in the December quarter 2019, subject to rig availability. Production of 1.4 million boe is expected from existing operations, comprising 6 PJ of gas from the Otway Basin and approximately 230,000 barrels of oil. Production arising from Sole commissioning, which is expected to commence in the final quarter of FY19, has not been included in firm guidance. Commercial activities will include concluding gas sales agreements for the supply of Casino Henry gas for the 2019 calendar year and contracting further tranches of Sole gas. Whereas previous marketing of Sole gas was conducted to secure long-term agreements to support project financing, the strategy for this new round of Sole gas contracting is likely to be directed to shorter term contracts and positions which optimise value for shareholders for gas reserves from anticipated market conditions. The completion of the Sole Gas Project will be the major development project for FY19, accounting for 79% of incurred capital expenditure forecast for the period. It is anticipated that pipeline and umbilical connection of the Sole production wells will be completed in January 2019. Commissioning involving Sole gas to the plant is expected from April 2019. In the Otway Basin, work is to be conducted on maintenance and repairs to the Casino Henry umbilical, expansion readiness and preparation for the Henry-2 sidetrack development well. The offshore drilling campaign being prepared for FY20 comprises up to 4 wells, 3 of which are expected to involve exploration for new gas reserves: the Manta Deep prospect and, subject to joint venture approval, 2 wells in VIC/P44. Planning for this campaign, including joint venture selection of targets for the exploration drilling in VIC/P44 is expected to occupy the major share of the Company’s exploration and subsurface efforts for the year. At this stage Cooper Energy expects to participate in one well during FY19, an exploration well planned for PEL-494 in the South Australian onshore Otway Basin. The well has the sandstones of the Pretty Hill Formation and the deeper Sawpit Sandstone successfully tested at the Haselgrove-3 well as its primary targets and will be part funded by a $6.89 million PACE grant from the South Australian government. Abandonment activities are planned in the Gippsland Basin, commencing with the abandonment of Sole-2 and then on legacy oil infrastructure at Basker Manta Gummy (“BMG”) in VIC RL/13, RL/14 and RL/15. 50 Operating and Financial Review For the year ended 30 June 2018 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 the Company had cash, deposits, financial assets and investments of $259.3 million and drawn debt of $125.9 million2. 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, $224.0 million is available, of which $98.1 million remains undrawn at 30 June 2018. The Company has additional liquidity of approximately $15 million through a working capital facility to be used for general business purposes, of which $0.9 million has been utilised in respect of bank guarantees with the remaining balance undrawn. Further information is detailed in Notes 2, 8 and 18 of the Financial Statements. The Company continues to assess value accretive funding options as it pursues near term growth opportunities. Risk Management The Company manages risks in accordance with its risk management policy with the objective of ensuring all risks inherent in oil and gas exploration and production activities are identified, measured and then managed or kept as low as reasonably practicable. The Management Team perform risk assessments on a regular basis and a summary is reported to the Risk and Sustainability Committee (previously The Audit and Risk Committee). The Committee approves and oversees an internal audit program undertaken internally and/or in conjunction with appropriate external industry or field specialists. Key risks which may materially impact the execution and achievement of the business strategies and prospects for Cooper Energy are summarised below and are risks largely inherent in the oil and gas industry. This should not be taken to be a complete or exhaustive list of risks nor are risks disclosed in any particular order. Many of the risks are outside the control of the Company and its officers. Appropriate policies and procedures are continually being developed and updated to manage these risks. Risk Exploration Development and Production Regulatory Description Exploration is a speculative activity with an associated risk of discovery to find any 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 that all major 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. Cooper Energy has a project risk management and reporting system to monitor the progress and performance of material projects and is subject to regular review by senior management and the Board. All major development and investment decisions are subjected to assurance reviews which includes experts and contractors where appropriate. Cooper Energy operates in a highly regulated environment. Cooper Energy complies with the regulatory authorities 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. 2 Shown as $116.9 million on the balance sheet, net of prepaid transaction costs. 51 Operating and Financial Review For the year ended 30 June 2018 Risk Management continued Risk Market Description The oil market and Australian domestic gas market are subject to the fluctuations of supply and demand and price. To the extent that future actions of third parties contribute to demand destruction or there is an expansion of alternative supply sources, there is a risk that this may have a material adverse effect on price for the oil and gas produced and the Company’s business, results of operations and financial condition. Cooper Energy regularly 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. 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. 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 and an HSEC management system to ensure safe and sustainable operations. The ability of the Company to achieve its stated objectives will depend on the performance of the counterparties under various agreements (including joint venture arrangements) it has entered into. If any counterparties do not meet their obligations under the respective agreements, this may impact on operations, business and financial conditions. 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. 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. Reserve management is consistent with the definitions and guidelines in the Society of Petroleum Engineers 2007 Petroleum Resources Management Systems. The assessment of Reserves and Resources is also subject to independent review from time to time. 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. Cooper Energy has a comprehensive approach to the management of risks associated with health, safety, environment and community which includes standards for asset reliability and integrity, as well as technical and operational competency requirements. Counterparties Reserves Environmental 52 Operating and Financial Review For the year ended 30 June 2018 Risk Management continued Risk Funding Description 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 condition 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. Abandonment liabilities 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 the construction of the facility and conducts a review on an annual basis. Any changes to the estimates of the provisions for restoration are recognised in line with accounting standards. Reconciliations for net profit/(loss) to Underlying net profit/(loss) and Underlying EBITDA Reconciliation to Underlying profit/(loss) Net profit/(loss) after income tax Adjusted for: Impairment of discontinued operations & loss on sale Gain on derecognition of investment in associate Exit provision Impairment of exploration and evaluation Restoration expense Gain on sale of subsidiary Gain on movement of consideration receivable Tax impact of above changes Underlying profit/(loss) Reconciliation to Underlying EBITDA* Underlying profit/(loss) Add back: Interest revenue Accretion expense Tax expense/(benefit) Depreciation Amortisation Underlying EBITDA* * Earnings before interest, tax, depreciation and amortisation $ million $ million $ million $ million $ million $ million $ million $ million $ million $ million $ million $ million $ million $ million $ million $ million $ million FY18 27.0 - (0.4) 0.2 0.7 4.9 (21.9) (0.5) (0.2) 9.8 FY18 9.8 (4.0) 2.7 4.0 0.6 19.6 32.6 FY17 (12.3) Change 39.3 1.0 - 4.0 - - (1.0) (0.4) (3.8) 0.7 4.9 % 320% -100% -100% -95% 100% 100% (1.4) (20.5) -1464% - - (8.7) (0.5) (0.2) 18.5 FY17 (8.7) Change 18.5 -100% -100% 213% % 213% (1.6) (2.4) -150% 2.5 2.9 0.3 9.8 5.3 0.2 1.1 0.3 9.8 27.3 8% 38% 100% 100% 515% 53 Directors’ Statutory Report For the year ended 30 June 2018 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 2018, and the independent auditor’s report thereon. 1. Directors The Directors of the parent entity at any time during or since the end of the financial year are: Mr John C. Conde AO B.Sc. B.E(Hons), MBA Chairman Independent Non-Executive Director Appointed 25 February 2013 Experience and expertise Mr Conde has extensive experience in business and commerce and in chairing high profile business, arts and sporting organisations. Previous positions include Non-executive Director of BHP Billiton, Chairman of Pacific Power (the Electricity Commission of NSW), 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) and the Sydney Symphony Orchestra (2007 – 2015) and is a former Director of AFC Asian Cup (2015) (2012 – 2015). Special Responsibilities Mr Conde is Chairman of the Board of Directors. He is also a member of the Remuneration and 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 Ltd. Special Responsibilities Mr Maxwell is Managing Director and is responsible for the day to day leadership of Cooper Energy. He is the leader of the management team. Mr Maxwell is also chair of the HSEC Committee (a management committee, not a Board committee). Experience and expertise Mr Gordon is a very successful geologist with over 35 years of experience in the petroleum industry. 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. Mr. Gordon’s previous employers also include Santos Limited, AGL Petroleum, TMOC Resources, Esso Australia and Delhi Petroleum Pty Ltd. Current and other directorships in the last 3 years Mr Gordon is a Director of Bass Oil Limited ASX: BAS (since 2014) and various wholly owned subsidiaries of Cooper Energy Limited. Special Responsibilities Mr Gordon is the Chairman of the Risk and Sustainability Committee and a member of the Audit Committee. Mr David P. Maxwell M.Tech, FAICD Managing Director Appointed 12 October 2011 Mr Hector M. Gordon B.Sc. (Hons). FAICD Executive Director 26 June 2012 – 23 June 2017 Non-Executive Director Appointed 24 June 2017 54 Director’s Statutory Report For the year ended 30 June 2018 1. Directors continued Mr Jeffrey W. Schneider B.Com Independent Non-Executive Director Appointed 12 October 2011 Ms Alice J. M. Williams B.Com, FAICD, FCPA, CFA Independent Non-Executive Director Appointed 28 August 2013 Ms Elizabeth A. Donaghey B.Sc., M.Sc. Independent Non-Executive Director Appointed 25 June 2018 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 is a former Director of Comet Ridge Limited ASX: COI (2003 – 2014). Special Responsibilities Mr Schneider is Chairman of the Remuneration and Nomination Committees and member of both the Risk and Sustainability Committee and 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, Telstra Sale Company, V/Line Passenger Corporation, State Trustees, Western Health and the Australian Accounting Standards Board. 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, Victorian Funds Management Corporation (since 2008), Barristers Chambers Ltd (since 2015), the Foreign Investment Review Board (since 2015), Defence Health (since 2010) and not for profit Tobacco Free Portfolios (since 2018). Ms Williams is a former council member of the Cancer Council of Victoria and former Non-executive Director of Guild Group and Port of Melbourne Corporation. Special Responsibilities Ms Williams is the Chairman of the Audit Committee and a member of both the Risk and Sustainability Committee and the Remuneration and Nomination 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 Australian Energy Market Operator (AEMO) (since 2017), Ms Donaghey is a former Director of Imdex Ltd (2009 - 2016), St Barbara Limited (2011 - 2014) and Australian Renewable Energy Agency (2012 - 2014). Special Responsibilities Ms Donaghey does not currently hold any Committee roles. 2. Company secretary Ms Alison Evans B.A., LLB was appointed to the position of Company Secretary and Legal Counsel on 25 February 2013. Ms Evans is an experienced company secretary and corporate legal counsel with extensive knowledge of corporate and commercial law in the resources and energy sectors. Ms Evans has been Company Secretary and/or Legal Counsel in a number of minerals and energy companies including Centrex Metals, GTL Energy and AGL. Ms Evans’ public company experience is supported by her work at leading corporate law firms. 55 Director’s Statutory Report For the year ended 30 June 2018 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 are: Director Board Meetings Mr J. Conde Mr D. Maxwell Mr H. Gordon Mr J. Schneider Ms A. Williams Ms E. Donaghey A 10 10 9 10 9 1 A = Number of meetings attended. B 10 10 10 10 10 1 Audit & Risk Committee Meetings Risk & Sustainability Meetings Remuneration and Nomination Committee Meetings A - - 4 4 4 - B - - 4 4 4 - A - - 3 3 2 - B - - 3 3 3 - A 3 - - 3 2 - B 3 - - 3 3 - B = Number of meetings held during the time the Director held office, or was a member of the committee, during the year 4. Remuneration Report Information about the remuneration of the Company’s key management personnel for the financial year ended 30 June 2018 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 Remuneration and Nomination Committee Dear Shareholder I am pleased to present our Remuneration Report for 2018 for which we will seek your support at the 2018 Annual General Meeting. The report is designed to provide information regarding our remuneration framework and the outcomes for the reporting period. Report context: 2018 Financial Year The Company’s performance in the 12 months to 30 June 2018 is reported in the Operating and Financial Review of the Financial Report. This performance, and that against the specific targets of the corporate scorecard provide the context of the Remuneration Report. Both the Operating and Financial Review and the Remuneration Report documents a company that has grown and created value over the short and longer term review periods and met or exceeded most of its benchmarks for 2018. Significantly, certain milestones Cooper Energy set for itself in its corporate scorecard were achieved at the stretch level. This included growth in production and revenue, progress of the Sole gas project and “enablers” such as cost management. In its first year as Operator of offshore gas producing and development assets, the Cooper Energy team should be commended. Market capitalisation of $433.4 million at 30 June 2017 was increased to $616.4 million at the conclusion of the year. For shareholders, a total shareholder return of 6% was recorded over the reporting period. The performance of the company and its shares in the period since balance date to the date of this report, while outside the scope of this remuneration report, is noteworthy retrospective affirmation of the strength of the position attained by Cooper Energy at 30 June 2018. As longer-term shareholders would be aware, the results achieved in 2018 have flowed from the disciplined application of a strategy by a stable and committed management team over several years to create value from opportunities foreseen in the south-east Australian gas market. This performance is congruent with the importance placed on long term and sustained value creation by the Board and the objectives of the Company’s remuneration framework. The performance of the company, its position at 30 June and the stability of its management team indicates that the company’s remuneration philosophy and framework have been effective in retaining, motivating and rewarding the existing team to deliver value for you, its shareholders. 56 Director’s Statutory Report For the year ended 30 June 2018 4. Remuneration Report continued Developments A significant development for the Company during the reporting period was the appointment of a new director. We were very pleased to welcome Ms Donaghey onto the board on 25 June 2018. We look forward to the significant contribution her skills and experience will bring. In terms of future developments in remuneration, we believe that the remuneration framework in place is working to deliver results and as such we are not proposing significant changes. The only changes we will be making are to the LTIP to reflect the fact that Cooper Energy is now a larger company albeit one from which further growth and scale is expected. In this regard, the Board has determined that the following changes will be made to the LTIP Invitations for the 2019 financial year: • The maximum award opportunity for the Managing Director will be reduced from a grant of 120% of his fixed annual remuneration to 100%; and • The performance period will remain for 3 years however there will no longer be any re-test at the end of that period. We thank the Managing Director, the management team and their teams for their commitment and contribution over the year. Yours sincerely Mr Jeffrey Schneider Chairman of the Remuneration and Nomination Committee 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 in place for key management personnel (KMP) for the reporting period. The Remuneration 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. Contents 4.1 Introduction 4.2 Key Management Personnel covered in this report 4.3 Remuneration governance 4.4 FY18 performance and Executive KMP outcomes 4.5 Nature of Executive KMP remuneration 4.6 Nature of Non-Executive Director remuneration 4.7 Statutory remuneration disclosures Page 57 57 58 58 62 65 66 4.2 Key Management Personnel covered in this Report In this Report, Key Management Personnel (KMP)are those individuals having the authority and responsibility for planning, directing and controlling the activities of the Group, either directly or indirectly. They comprise: • Non-executive Directors; • The Managing Director; and • the executives on the management team. The Managing Director and other executives on the management 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 Mr J. Schneider Ms A. Williams Mr H. Gordon Ms E. Donaghey Position Chairman Non-executive Director Non-executive Director Non-executive Director Non-executive Director Dates Full reporting period Full reporting period Full reporting period Full reporting period From 25 June 2018 57 Director’s Statutory Report For the year ended 30 June 2018 4. Remuneration Report continued 4.2 Key Management Personnel covered in this Report continued Executive KMP Mr D. Maxwell Mr A. Thomas Mr E. Glavas Ms A. Evans Mr I. MacDougall Ms V. Suttell Mr D. Clegg Mr M. Jacobsen Position Managing Director General Manager Exploration & Subsurface Dates Full reporting period Full reporting period General Manager Commercial & Business Development Full reporting period Company Secretary and Legal Counsel General Manager Operations Chief Financial Officer General Manager Development General Manager Projects Full reporting period Full reporting period Full reporting period Full reporting period Full reporting period 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 emphasises superior performance and shareholder returns. Cooper Energy’s approach towards remuneration aims to ensure that an appropriate balance is achieved among: • maximising sustainable 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; • achieve the most effective returns (employee productivity) for total employee spend; and • ensure remuneration transparency and credibility for all employees and in particular for Executive KMP. Cooper Energy’s policy is to pay fixed remuneration (base salary and superannuation) 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 Remuneration and Nomination Committee The Company’s Remuneration and Nomination Committee (comprised during the reporting period of 3 Non-executive Directors, all of whom are independent) makes recommendations to the Board regarding remuneration strategies and policies in relation to KMP. The Committee assesses annually the nature and amount of Executive KMP remuneration by reference to relevant employment market conditions and third party remuneration benchmark reports. The Committee determines remuneration arrangements in conjunction with the annual performance reviews of the Executive KMP. 4.3.3 External remuneration advisers From time to time, the Remuneration and Nomination Committee seeks and considers 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 Remuneration and Nomination 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. 4.4 FY18 performance and Executive KMP pay outcomes 4.4.1 Remuneration actually delivered to Executives in FY18 (not audited) The Company believes that reporting remuneration actually delivered to 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. 58 Director’s Statutory Report For the year ended 30 June 2018 4. Remuneration Report continued 4.4 FY18 performance and Executive KMP pay outcomes continued 4.4.1 Remuneration actually delivered to Executives in FY18 (not audited) continued 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 4.7.3 and 4.7.4. The information in this section 4.4.1 is not audited. The total benefits actually delivered during the reporting period and set out in the table below comprise several elements including: • fixed remuneration being base salary and superannuation; • STI cash payment made in October 2017 being the STIP awarded for performance during the prior period (FY17); • the market value of shares issued in FY18 on the vesting of performance rights granted September 2014. The market value is taken to be the share price at the date of issue of the shares; • the value of other short term benefits including fringe benefits on accommodation, car parking and other benefits. Name Year Fixed Remuneration $ STIP $ LTIP $ Other $ Termination Payments $ Total $ Executive Directors Mr D. Maxwell Mr H. Gordon1 Executives Mr A. Thomas Ms V. Suttell2 Ms A. Evans3 Mr I. MacDougall Mr E. Glavas Mr D. Clegg4 Mr M. Jacobsen5 Mr J. de Ross6 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 787,500 325,000 210,791 667,500 643,940 422,608 - - - 78,012 88,691 - 231,718 155,171 245,348 6,466 416,250 381,762 393,750 107,620 317,125 223,274 416,250 374,411 366,250 297,764 80,000 174,400 57,000 - 54,800 99,320 80,000 174,400 70,000 143,360 455,417 100,000 75,359 152,824 - - 34,867 68,040 72,268 88,930 49,185 - - 386,803 383,683 - - - 31,500 15,000 - - - - - 6,382 6,192 6,382 2,453 6,382 6,603 6,382 6,649 6,382 6,466 536 92 536 - - - - - - - - - - - - - - - - - - - - - 1,401,303 1,822,739 - 638,703 577,991 715,178 457,132 110,073 413,174 397,237 574,900 644,390 491,817 447,590 555,953 418,395 399,219 - - 176,868 136,953 411,691 3,240 283,371 1,012,123 1. Mr Gordon was no longer an executive from 24 June 2017. 2. Ms Suttell commenced employment with the Company in an acting capacity part time (0.8 full time equivalent) on 18 January 2017. She modified her hours to full time from 1 June 2017. 3. Ms Evans worked part time (0.8 full time equivalent for the period 1 February 2017 to 31 January 2018; and 0.9 full time equivalent for the period 1 February 2018 to 30 June 2018) and accordingly her entitlements are prorated. 4. Mr Clegg commenced employment with the Company as General Manager Development on 1 May 2017. Prior to that time, he was engaged by the Company as a contractor on a part time basis and was not considered KMP during this period. The amounts shown in the table above include the total remuneration paid during the reporting period, including as a contractor. 5. Mr Jacobsen commenced employment with the Company and General Manager Projects on 1 July 2017. 6. Mr de Ross left employment on 9 December 2016. His termination payment included the payout of unused annual leave entitlements. 59 Director’s Statutory Report For the year ended 30 June 2018 4. Remuneration Report continued 4.4 FY18 performance and Executive KMP pay outcomes continued 4.4.1 Remuneration actually delivered to Executives in FY18 (not audited) continued STI payments are generally made for performance over a 12 month period, however the acquisition of the Victorian gas assets from Santos Limited during the 2017 financial year was an extraordinary event which transformed the Company and necessitated a re-set of the scorecard performance measures as at 1 January 2017. As reported in the 2017 Annual Report, an interim STIP award was made to employees in January 2017. The STI payments made to Executive KMP detailed in the table above and paid in October 2017, relate only to performance during the period 1 January 2017 to 30 June 2017 and comprise one half of the total STIP paid in respect of the second half of the 2017 financial year (6 months). The STI payments made to Executive KMP detailed in the table above and paid during the 2017 financial year comprise STIP paid in respect of the whole of 2016 financial year and the first half of the 2017 financial year (18 months). 4.4.2 Cooper Energy five-year performance Operational Annual production Proved & Probable Reserves TRCFR1 Financial Sales revenue Profit after tax Earnings per share Total shareholder return Capital as at 30 June Share price Market capitalisation MMboe MMboe events per hours worked $ million $ million cents percent $ per share $ million 1. Total Recordable Case Frequency Rate 4.4.3 STIP outcomes 2014 0.59 2.01 2.52 72.3 22.0 6.4 34.7 0.505 166.3 12 months to 30 June 2015 0.48 3.08 4.18 39.1 (63.5) (19.2) (51.5) 0.245 81.4 2016 0.46 3.00 0.00 27.4 (34.8) (10.1) (12.2) 0.215 93.6 2017 0.96 11.7 1.98 39.1 (12.3) (1.8) 72.7 0.38 433.4 2018 1.49 52.4 4.07 67.5 27.0 1.8 6.0 0.39 616.4 The Scorecard results for the reporting period ranged between Target and Stretch. The final STIP results for the reporting period, in conjunction with individual performance reviews will be determined in September and form the basis of individual STIP payments in October 2018. Performance measures in company scorecard Weighting Scorecard Result Comment HSEC 20% Stretch Production and revenue (existing permits) Major Projects 20% 20% Stretch Stretch TRCFR 4.07 – consistent with NOPSEMA average of 4.02. Major work has been undertaken by the Company to enhance HSEC processes and to prepare and submit regulatory documents to support being an offshore operator and the increased activity this has brought. Production of 1.49 MMboe is at the high end of guidance and increased gas and oil prices positively impacting revenue. As at 30 June 2018 the Sole Gas Project was ahead of schedule and well within budget. 60 Director’s Statutory Report For the year ended 30 June 2018 4. Remuneration Report continued 4.4 FY18 performance and Executive KMP pay outcomes continued Weighting Scorecard Result Comment Key gas strategy milestones 20% Target Reserve additions have replaced production. The Company’s clear South-east Australia strategy has created opportunities such as the Minerva Gas Plant acquisition and the award of the VIC/P72 exploration permit. 20% Stretch Costs are below budget and processes and funding have improved significantly. External staff survey has been conducted and concluded high people engagement and enablement. 4.4.3 STIP outcomes continued Performance measures in company scorecard Growth in reserves and resources Acquisitions and divestments Cost management Processes and risk management People and stakeholder relationships 4.4.4 LTIP outcomes The Company’s total shareholder return relative to the peer group against which it is measured is set out below. The graph commences December 2015, the time the first grant of performance rights and share appreciation rights were made under the Company’s Equity Incentive Plan (EIP). Rights will vest and shares will be issued for the first time under this plan in December 2018. The terms of the EIP are set out in section 4.5.3. Relative Total Shareholder Return - 15 December 2015 to 30 June 2018 -100% -50% 0% 50% 100% 150% 200% 250% 300% 350% Cooper Energy Limited 188% 327% 263% 237% 81% 57% 36% 17% 8% -45% -47% -72% During the reporting period, shares were issued to Executive KMP on the vesting of performance rights granted in September 2014 under the 2011 Plan. Under that plan, 75% of the performance rights were tested against relative total shareholder return and 25% were tested against absolute shareholder return after the end of the measurement period. The results are set out below: 2011 Plan Award Award 7 (granted September 2014) Start VWAP End VWAP Cooper Energy TSR TSR Rank Absolute TSR Achieved Relative TSR Achieved 0.3938 0.2906 -26.21% 1st against peer group 0.00% 100.00% 61 Director’s Statutory Report For the year ended 30 June 2018 4. Remuneration Report continued 4.5 Nature of Executive KMP remuneration Executive KMP remuneration during the reporting period consisted of: • base salary and statutory superannuation; • short term incentive plan (being performance based cash bonuses); • other short term benefits such as accommodation, internet allowance and carparking; and • long term incentive plan (currently comprising the award of performance rights and share appreciation rights under the Company’s Equity Incentive Plan (EIP)). It is the Company’s policy that the performance based (or at risk) pay of Executive KMP forms a significant portion of their total remuneration. In addition, within performance based pay, an appropriate balance is targeted between rewarding operational performance (through the short term incentive cash bonuses) and rewarding long-term sustainable performance (through the long term incentive plan). The Company’s remuneration profile for Executive KMP is as follows: Remuneration Element Expressed as percentage of fixed remuneration at target level performance Expressed as percentage of fixed remuneration at maximum (super stretch) level performance Fixed Remuneration STIP (at risk) LTIP1 (at risk) Total Managing Director 100% 50% 100% 250% Other Executive KMP 100% 25% 70% 195% Managing Director 100% 100% 100% 300% Other Executive KMP 100% 50% 70% 220% 1. Reflects face value of LTIP at grant date however may not necessarily reflect the amount that will ultimately vest and be exercised. 4.5.1 Fixed Remuneration Fixed Remuneration includes base salary (paid in cash) and statutory superannuation. Executives are paid base salaries which are competitive in the markets in which the Company operates and are consistent with the responsibilities, accountabilities and complexities of the respective roles. The Company benchmarks Executive KMP base salaries against hydrocarbon industry market surveys which are published annually. Additionally, the pay levels of Executive 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 base salaries. 4.5.2 Short term incentive plan (STIP) - Overview The key features of the STIP for the financial year 2018 are set out in the following table: 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. What is the maximum award opportunity (% of fixed remuneration)? Managing Director Management Team 100% 50% What is the performance period? Each year, the Board reviews and approves the performance criteria for the year ahead by approving a Company scorecard. The Company’s STIP operates over a 12 month performance period from 1 July to 30 June. 62 Director’s Statutory Report For the year ended 30 June 2018 4. Remuneration Report continued 4.5 Nature of Executive KMP remuneration continued 4.5.2 Short term incentive plan (STIP) - Overview continued How are the performance measures determined and what are their relative weightings? The measurement of Company performance is based on the achievement of key performance indicators (KPIs) set out in a Company scorecard. 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 (ie maximum). Personal performance measures are agreed between each Executive KMP and Cooper Energy each year. The relative weighting of Company and individual performance varies dependant on the seniority of the Executive KMP and is as follows: • Managing Director: 75% Company: 25% individual • Executives 70% Company; 30% individual All performance measures are relevant to the Company’s strategic objectives and designed to motivate Executive KMP to meet goals which enhance shareholder value. 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 expected level of performance (base)). 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. When are STIP payments made? STIP payments, are generally made in October each year. Irrespective of the scorecard outcome, payment of any STIP is entirely at the discretion of the Board. 4.5.3 Long term incentive plan (LTIP) - Overview In the reporting period, the LTIP involved grants of performance rights and share appreciation rights under the Equity Incentive Plan approved by shareholders at the 2015 AGM (EIP). A “refresh” of this approval will be sought at the 2018 AGM. It is proposed that future grants will be made under the EIP. The key features of the grants made in the 2018 financial year (granted December 2017) are set out in the following table: Plan Feature Details What is the purpose of the LTIP? How is the LTIP aligned to shareholder interests? What is the vehicle 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 3 years before securities under the plan are available to employees). 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. During the reporting period, the LTIP involved grants of 50% Performance Rights and 50% Share Appreciation Rights (SARs). A performance right is a right to acquire one fully paid share in the Company provided a specified hurdle is met. Share Appreciation Rights (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 award opportunity (% of fixed remuneration)? Managing Director Executive KMP Senior staff 120% 70% 50% 63 Director’s Statutory Report For the year ended 30 June 2018 4. Remuneration Report continued 4.5 Nature of Executive KMP remuneration continued 4.5.3 Long term incentive plan (LTIP) - Overview continued Plan Feature Details What is the performance period? The performance period is 3 years. Additionally, the LTIP allows for re-testing 12 months following the end of the performance period. What are the performance measures? A re-test was considered appropriate because the Company’s growth is dependent on development of projects that will likely take greater than 3 years from conception to start- up. Given the growth of the Company, including growth in its development activities and no longer being reliant on single projects, the Board has considered the re-test provision and has determined that it will not form part of the grant of Incentives for the 2019 financial year. 100% of the grant (both performance rights and SARs) is subject to a relative total shareholder return performance (RTSR) measure. RTSR is a common LTI measure across ASX-listed companies and is aligned with shareholder returns. Relative measures ensure that maximum incentives are only achieved if Cooper Energy’s performance exceeds that of its peers and therefore supports competitive returns against other comparable organisations. In addition to the RTSR performance measure set by the Board, SARs by their nature also have a natural absolute total shareholder return measure. No SARs will be exercisable unless the share price appreciates over the measurement period. What is the vesting schedule? The level of vesting will be determined based on the ranking against the comparator Group of companies in accordance with the following schedule: Which companies make up the Relative TSR peer group? • 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 • 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. The RTSR 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 Limited; AWE Limited; Blue Energy 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 Australian operations and a range of market capitalisation. What happens on cessation of employment? Generally, if an employee ceases employment prior to the vesting date, they will forfeit all awards. Exceptional circumstances may be approved by the Board in the event of redundancy, retirement or incapacity, and may result in a prorate number of awards being retained. What happens if there is a change of control? In the event of a change of control, the Board has the discretion to approve pro-rata vesting based on service and performance. Who can participate in the LTIP? Eligibility is generally restricted to Executive KMP and senior staff who are in a position to influence shareholder value the most. Staff not offered the opportunity to participate in the LTIP are given the opportunity to become shareholders by receiving a deferred component of a STIP which will be paid in equity. Is there a cap on dilution? 5% total on issue (excluding KMP). 64 Director’s Statutory Report For the year ended 30 June 2018 4. Remuneration Report continued 4.5 Nature of Executive KMP remuneration continued 4.5.3 Long term incentive plan (LTIP) - Overview continued Plan Feature Details What is the 2011 Plan referred to in this Report? The 2011 plan refers to the Cooper Energy Employee Incentive Plan which was approved by shareholders at the 2011 annual general meeting. The 2011 Plan has now been superseded by the Equity Incentive Plan (EIP)approved by shareholders at the 2015 annual general meeting (such approval to be “refreshed” at the 2018 annual general meeting) and grants are now made under the EIP. The 2011 Plan is referred to in this Report because some Executive KMP were granted shares on the vesting of performance rights granted in September 2014 under the 2011 Plan. The last of the performance rights granted under the 2011 Plan have now vested or have been cancelled. Will the Company make any changes to the LTIP for the grant to be made in the 2019 financial year? The general structure of the LTIP will not change for grants made in the 2019 financial year however, the Board has determined to make some changes to certain aspects of the LTIP. The changes are: • The maximum award opportunity for the Managing Director will be reduced from a grant to the value of 120% of his fixed annual remuneration to 100%. • The performance period will remain for 3 years however there will no longer be any re-test at the end of that period. 4.5.4 Executive KMP employment contracts Mr David Maxwell – Managing Director Mr Maxwell commenced as Managing Director on 12 October 2011 under a contract of employment. The initial term of the Managing Director’s contract expired on 10 October 2014 and was renewed to end on 31 July 2019. On 1 August 2018 Mr Maxwell’s contract of employment was amended to remove the fixed term and therefore the contract must be terminated in accordance with the notice provisions in the contract of employment. The Company may terminate the contract by providing twelve months written notice or payment in lieu of notice. The Company may also terminate the contract immediately for cause. Mr Maxwell may terminate the contract by providing 6 months’ written notice. Deed of indemnity The Company also entered into a deed of indemnity, insurance and access with the Managing Director under which the Company will, on the terms set out in the deed, provide an indemnity, maintain an appropriate level of Directors’ and Officers’ indemnity insurance and provide access to Company records. Other Executive KMP The Company has entered into a contract of employment with each Executive KMP. The term of each contract continues until termination. The Company may terminate the contract by providing six months’ notice or payment in lieu of notice. The Company may also terminate the contract immediately for cause. The Executive may terminate the contract by providing 3 months’ written notice. 4.6 Nature of Non-executive Director remuneration Non-executive Directors are remunerated solely by way of fees and statutory superannuation and their remuneration is reviewed annually to ensure that the fees reflect the demands on, and responsibilities of such Directors. Non-executive Directors do not receive any performance related remuneration. The maximum aggregate remuneration pool for Non-executive Directors, as approved by shareholders at the Company’s 2014 Annual General Meeting, is $750,000 per annum. This pool is nearly fully utilised. Since the 2014 Annual General Meeting, Mr Gordon has changed roles from an Executive Director to a Non-executive Director and Ms Donaghey joined the Board as a Non-executive Director. The Board has therefore determined to ask shareholders to approve an increase of the aggregate remuneration pool to $1.25 million at the 2018 Annual General Meeting. This would accommodate the appointment of a new Director if determined appropriate by the Board and increases to the Directors’ fees in the medium term. Remuneration paid to the Non-executive Directors for the reporting period and for the previous reporting period is shown in the table in Section 4.7.3 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. 65 Director’s Statutory Report For the year ended 30 June 2018 4. Remuneration Report continued 4.6 Nature of Non-executive Director remuneration continued The Company has entered into deeds of indemnity, insurance and access with each of the Non-executive Directors under which the Company will, on the terms set out in the deed, provide an indemnity, maintain an appropriate level of Directors’ and Officers’ indemnity insurance and provide access to Company records. 4.7 Statutory remuneration disclosures 4.7.1 Accounting for performance rights The value of the performance rights issued under the 2011 Plan and EIP is recognised as Share Based Payments in the Company’s statement of comprehensive income and amortised over the vesting period. Performance rights and share appreciation rights were granted under the EIP on 8 December 2017. The performance rights and share appreciation rights 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. Performance rights and share appreciation rights granted under the EIP were valued by an independent consultant who applied the Monte Carlo simulation model to determine the probability of achievement of the absolute shareholder total return (ASTR), and relative shareholder total return (RSTR), performance conditions (as described in Section 4.5 above). The value of performance rights and share appreciation rights shown in the tables below are the accounting fair values for grants in the reporting period: Performance Rights (2011 Plan) Performance Rights (EIP) Share Appreciation Rights (EIP) 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 2018 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 2018 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 2018 Executive Directors Mr D. Maxwell nil - 1,086,553 100% 1,629,327 $364,969 Executives Mr A. Thomas Ms V. Suttell Ms A. Evans Mr I. MacDougall Mr E. Glavas Mr D. Clegg Mr M. Jacobsen nil nil nil nil nil nil nil - 388,446 100% 498,981 $111,722 - - - 487,101 $109,111 - 179,727 100% 400,967 $89,817 - 372,516 100% 498,981 $111,772 - 253,529 100% 445,519 $99,796 - - - - - - 594,025 $133,062 498,981 $111,722 - - - - - - - - - 4,092,071 $507,417 - 1,253,196 $155,396 - 1,223,358 $151,696 - 1,007,033 $124,872 - 1,253,196 $155,396 - 1,118,925 $138,747 - 1,491,901 $184,996 - 1,253,196 $155,396 - - - - - - - - - - - - - - - - The vesting date of the performance rights granted on 8 December 2017 is 8 December 2020. The fair value of these rights is $0.224 per right. These performance rights have a commencement date of 8 December 2017. The vesting date of the share appreciation rights granted on 8 December 2017 is 8 December 2020. The fair value of these rights is $0.124 per right. These share appreciation rights have a commencement date of 8 December 2017. 66 Director’s Statutory Report For the year ended 30 June 2018 4. Remuneration Report continued 4.7 Statutory remuneration disclosures continued 4.7.2 Additional remuneration disclosures Movement in performance rights The movement during the reporting period in the number of performance rights 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 (2011 Plan) Held at 1 July 2017 Granted Lapsed Vested & Exercised Held at 30 June 2018 Directors Mr D. Maxwell Mr H. Gordon1 Executives Mr A. Thomas Ms V. Suttell Ms A. Evans Mr I. MacDougall Mr E. Glavas Mr D. Clegg Mr M. Jacobsen 1,448,737 419,825 517,929 - 239,634 496,689 338,039 - - - - - - - - - - - 362,184 104,955 1,086,553 314,870 129,483 388,446 - 59,907 124,173 84,510 - - - 179,727 372,516 253,529 - - - - - - - - - - - 1. Performance Rights were granted to Mr Gordon when he was an Executive Director. The performance rights lapsed during the period noted in the table above were granted in December 2014. Performance Rights (EIP) Held at 1 July 2017 Granted Lapsed Vested & Exercised Held at 30 June 2018 Directors Mr D. Maxwell Mr H. Gordon1 Executives Mr A. Thomas Ms V. Suttell Ms A. Evans Mr I. MacDougall Mr E. Glavas Mr D. Clegg Mr M. Jacobsen 3,407,214 987,364 1,218,091 - 597,278 1,168,139 868,158 - - 1,629,327 - 498,981 487,101 400,967 498,981 445,519 594,025 498,981 1. Performance Rights were granted to Mr Gordon when he was an Executive Director. - - - - - - - - - - - - - - - - - - 5,036,541 987,364 1,717,072 487,101 998,245 1,667,120 1,313,677 594,025 498,981 67 Director’s Statutory Report For the year ended 30 June 2018 4. Remuneration Report continued 4.7 Statutory remuneration disclosures continued 4.7.2 Additional remuneration disclosures continued Share Appreciation Rights (EIP) Held at 1 July 2017 Granted Lapsed Vested & Exercised Held at 30 June 2018 Directors Mr D. Maxwell Mr H. Gordon1 Executives Mr A. Thomas Ms V. Suttell Ms A. Evans Mr I. MacDougall Mr E. Glavas Mr D. Clegg Mr M. Jacobsen 9,334,554 2,705,027 3,337,135 - 1,634,581 3,200,285 2,378,444 - - 4,092,071 - 1,253,196 1,223,358 1,007,033 1,253,196 1,118,925 1,491,901 1,253,196 - - - - - - - - - - - - - - - - - - 13,426,625 2,705,027 4,590,331 1,223,358 2,641,614 4,453,481 3,497,369 1,491,901 1,253,196 1. Share Appreciation Rights were granted to Mr Gordon when he was an Executive Director. 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 2017 Purchases Received on vesting of performance rights Sales Held at 30 June 2018 Directors Mr J. Conde AO Mr D. Maxwell Ms E. Donaghey Mr H. Gordon Mr J. Schneider Ms A. Williams Executives Mr A. Thomas Ms V. Suttell Ms A. Evans Mr I. MacDougall Mr E. Glavas Mr D. Clegg Mr M. Jacobsen Options 613,638 8,178,656 - 1,360,731 726,138 118,638 245,455 2,112,123 - - 290,456 47,456 - 1,086,553 - - - - 314,870 632,000 - - 1,781,364 - 388,446 29,000 430,500 527,592 - 125,000 - 11,600 172,200 162,038 33,060 10,000 - - 179,727 372,516 253,529 - - 859,093 11,377,332 - 1,043,601 1,016,594 166,094 2,169,810 40,600 782,427 1,062,146 286,589 135,000 - - - - - - - - - - No options were issued (or forfeited) during the year. 68 Director’s Statutory Report For the year ended 30 June 2018 4. Remuneration Report continued 4.7 Statutory remuneration disclosures continued 4.7.3 Table of Directors’ remuneration for 2017 and 2018 financial years Benefits Short-term Base Salary & Fees STIP Other Short-term Benefits(a) Directors Mr J. Conde AO $ 2018 191,781 2017 161,644 Mr J. Schneider 2018 118,722 2017 103,402 $ - - - - $ - - - - Long Term Long Service Leave $ - - - - Mr D. Maxwell 2018 767,451 667,186 78,012 29,253 2017 647,884 498,421 88,691 38,938 Post Employment Share Based Remuneration(c) Superannuation(b) LTIP Total $ 18,219 15,356 11,279 9,823 20,049 19,616 $ - - - - $ 210,000 177,000 130,001 113,225 684,776 2,246,727 554,317 1,847,867 Mr H. Gordon(d) 2018 118,722 23,861 - 2017 212,241 113,472 6,466 Ms A. Williams 2018 118,722 Ms E. Donaghey(e) 2017 103,402 2018 2017 2,101 - - - - - - - - - - - - - - - 18,689 149,283 310,555 19,476 179,088 530,743 11,279 9,823 200 - - - - - 130,001 113,225 2,301 - a) Other short term benefits include fringe benefits on accommodation, car parking and other benefits. b) Superannuation includes the amounts required to be contributed by the Company and does not include amounts salary sacrificed. c) 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 performance rights 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 performance rights 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 25 of the Notes to the Financial Statements. None of the performance rights issued vested and no payments were made for performance rights during the current financial year. d) Performance rights and share appreciation rights were granted to Mr Gordon when he was an Executive Director. e) Ms Donaghey was appointed a Non-executive Director of the Company effective from 25 June 2018. 69 Director’s Statutory Report For the year ended 30 June 2018 4. Remuneration Report continued 4.7 Statutory remuneration disclosures continued 4.7.4 Table of Executives’ remuneration for 2017 and 2018 financial years Short-term Base Salary STIP Benefits Other Short-term Benefits(a) Long Term Long Service Leave Post Employment Share Based Remuneration(c) Superannuation(b) LTIP Termination Payments Total Executives Mr A. Thomas $ $ $ $ 2018 396,201 161,569 6,382 12,825 2017 362,147 128,902 6,192 14,494 Ms V. Suttell (d) 2018 373,701 175,493 6,382 2017 98,673 26,330 2,453 - - Ms A. Evans(e) 2018 297,076 133,698 6,382 20,916 2017 203,658 82,521 6,603 9,134 Mr I. MacDougall 2018 396,201 161,569 6,382 11,780 2017 354,796 127,084 6,649 32,245 Mr E. Glavas 2018 346,201 145,673 6,382 34,033 2017 278,148 113,328 6,466 Mr D. Clegg(f) 2018 435,368 249,958 2017 383,534 21,201 Mr M. Jacobsen(g) 2018 363,634 149,869 Mr J. de Ross(h) 2017 2018 2017 - - - - 158,367 49,031 3,240 536 92 536 - - - - - - - - - $ 20,049 19,616 20,049 8,947 20,049 19,616 20,049 19,616 20,049 19,616 20,049 3,269 20,049 - - $ $ $ 236,115 198,431 50,713 - 132,709 95,395 281,444 146,609 177,141 122,724 61,844 31,500 51,949 - - - 833,141 - 729,782 - 626,338 - 136,403 - 610,830 - 416,927 - 877,425 - 686,999 - 729,479 - 540,282 - 767,755 - 439,596 - 586,037 - - - - 18,501 67,696 283,371 580,206 a) Other short term benefits include fringe benefits on accommodation, car parking and other benefits. b) Superannuation includes the amounts required to be contributed by the Company and does not include amounts salary sacrificed. c) 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 performance rights 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 performance rights was determined in accordance with AASB 2 Share-based Payments and is discussed in Section 4.11 above and in more detail in Note 25 of the Notes to the Financial Statements. None of the performance rights issued vested and no payments were made for performance rights during the current financial year. d) Ms Suttell commenced employment with the Company in an acting capacity part time (0.8 full time equivalent) on 18 January 2017. She modified her hours to full time from 1 June 2017. e) Ms Evans worked part time (0.8 full time equivalent for the period 1 February 2017 to 31 January 2018; and 0.9 full time equivalent for the period 1 February 2018 to 30 June 2018) and accordingly her entitlements are prorated. f) Mr Clegg commenced employment with the Company as General Manager Development on 1 May 2017. Prior to that time, he was engaged by the Company as a contractor on a part time basis and was not considered KMP during this period. The amounts shown in the table above include the total remuneration paid during the reporting period, including as a contractor. g) Mr Jacobsen commenced employment with the Company and General Manager Projects on 1 July 2017. h) Mr de Ross left employment on 9 December 2016. His termination payment included the payout of unused annual leave entitlements. End of remuneration report. 70 Director’s Statutory Report For the year ended 30 June 2018 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 Group 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: Mr J. Conde AO Mr D. Maxwell Mr H. Gordon Mr J. Schneider Ms A. Williams Ms E. Donaghey Cooper Energy Limited Ordinary Shares Performance Rights Share Appreciation Rights 859,093 11,377,332 1,043,601 1,016,594 166,094 - - 5,036,541 987,364 - - - - 13,426,625 2,705,027 - - - 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 17,846,179 outstanding performance rights and 46,017,694 share appreciation rights under the Equity Incentive Plan approved by shareholders at the 2015 AGM. During the financial year 4,305,751 shares were issued as a result of performance rights exercised. At the date of this report, no performance rights have vested and been exercised subsequent to 30 June 2018. 12. Events after financial reporting date Refer to Note 28 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 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. No proceedings have been brought or intervened in on behalf of Cooper Energy Limited with leave of the Court under section 237 of the Corporations Act. 71 Director’s Statutory Report For the year ended 30 June 2018 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 2018. 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 $172,187 (2017: $65,000). 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 13 August 2018 72  Cooper Energy Limited and its controlled entities Financial Statements For the year ended 30 June 2018 73 Consolidated Statement of Comprehensive Income For the year ended 30 June 2018 Continuing Operations Revenue from sales Cost of sales Gross profit Other revenue Gain on sale of subsidiary Exploration and evaluation expenditure written off Finance costs Impairment Other expenses Profit/(Loss) before tax Income tax benefit Petroleum Resource Rent Tax expense Total tax expense Consolidated 2018 $’000 67,452 (38,464) 28,988 4,933 21,934 (850) (2,779) (696) 2017 $’000 34,648 (20,058) 14,590 1,614 - (1,577) (2,555) - (20,511) (19,107) 31,019 4,781 (8,789) (4,008) (7,035) 4,786 (7,598) (2,812) Notes 4 4 4 6 4 13 4 5 Net profit/(loss) after tax from continuing operations 27,011 (9,847) Discontinued operations Loss for the year from discontinued operations Total profit/(loss) for the period attributable to shareholders Other comprehensive income/(expenditure) Items that will be reclassified subsequently to profit or loss Foreign currency translation reserve Reclassification of foreign currency translation reserve on disposal of subsidiary Fair value movements on oil price options accounted for in a hedge relationship Fair value movements on interest rate swaps accounted for in a hedge relationship Reclassification during the period to profit or loss of realised hedge settlements 21 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 11 Other comprehensive income/(expenditure) for the period net of tax - 27,011 (2,465) (12,312) - - 258 (481) 280 92 1,230 1,379 (297) (835) 736 - 494 (369) (132) (403) Total comprehensive gain/(loss) for the period attributable to shareholders 28,390 (12,715) Basic earnings per share from continuing operations Diluted earnings per share from continuing operations Basic earnings per share Diluted earnings per share 7 7 7 7 cents 1.8 1.8 1.8 1.8 cents (1.4) (1.4) (1.8) (1.8) 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 2018 Consolidated 2018 $’000 2017 $’000 Notes Assets Current Assets Cash and cash equivalents Other financial assets Trade and other receivables Inventory Prepayments Assets classified as held for sale Total Current Assets Non-Current Assets Equity instruments Trade and other receivables Prepayments Term deposits at banks Other financial assets Deferred tax assets Oil and gas assets Property, plant and equipment Exploration and evaluation Total Non-Current Assets Total Assets Liabilities Current Liabilities Trade and other payables Provisions Other financial liabilities Liabilities and provisions classified as held for sale Total Current Liabilities Non-Current Liabilities Deferred Petroleum Resource Rent Tax liability Provisions Government grants Interest bearing loans and borrowings Other financial liabilities Total Non-Current Liabilities Total Liabilities Net Assets Equity Contributed equity Reserves Accumulated losses Total Equity 8 20 9 10 11 9 10 8 20 5 12 14 15 16 17 20 5 17 18 20 19 19 19 The above Consolidated Statement of Financial Position should be read in conjunction with the accompanying notes. 236,907 147,425 20,171 27,330 467 2,761 287,636 - 287,636 2,241 156 - 16 20,146 10,334 394,632 2,864 98,732 529,121 816,757 59,215 73,812 591 133,618 - - 10,878 2,000 1,902 162,205 25,090 187,295 658 2,997 911 41 - 4,315 69,402 3,694 223,331 305,349 492,644 58,520 19,188 114 77,822 25,448 133,618 103,270 10,356 106,680 2,067 116,923 3,231 239,257 1,481 99,802 - - 3,044 104,327 372,875 207,597 443,882 285,047 471,837 9,925 (37,880) 443,882 343,161 6,777 (64,891) 285,047 75 Consolidated Statement of Changes in Equity For the year ended 30 June 2018 Balance at 1 July 2017 Profit for the period Other comprehensive income Total comprehensive income for the period Transactions with owners in their capacity as owners: Share based payments Transferred to issued capital Share issued Balance at 30 June 2018 Balance at 1 July 2016 Loss for the period Other comprehensive expenditure Total comprehensive expenditure for the period Transactions with owners in their capacity as owners: Share based payments Transferred to issued capital Shares issued Balance at 30 June 2017 Issued Capital Reserves Accumulated Losses $’000 $’000 $’000 343,161 - - - - 873 127,803 471,837 137,558 - - - 223 1,440 203,940 343,161 6,777 - 1,379 1,379 2,642 (873) - 9,925 6,571 - (403) (403) 2,049 (1,440) - 6,777 (64,891) 27,011 - 27,011 - - - (37,880) (52,579) (12,312) - (12,312) - - - (64,891) Total Equity $’000 285,047 27,011 1,379 28,390 2,642 - 127,803 443,882 91,550 (12,312) (403) (12,715) 2,272 - 203,940 285,047 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 2018 Consolidated 2018 $’000 2017 $’000 Notes Cash Flows from Operating Activities Receipts from customers Payments to suppliers and employees Exit penalties Payments for restoration Petroleum Resource Rent Tax paid Interest received Net cash from operating activities Cash Flows from Investing Activities Transfers of term deposits Transfers to escrow proceeds receivable Receipts from disposal of property, plant and equipment Payments of contingent consideration Payments of consideration Receipts for assumption of rehabilitation provisions Receipts from sale of subsidiary Payments for exploration and evaluation Net cash transfer on disposal of subsidiary Acquisition of exploration and evaluation and gas assets Interest paid Payments for oil and gas assets Net cash flows used in investing activities Cash Flows from Financing Activities Proceeds from equity issue Proceeds from borrowings Transaction costs associated with borrowings Net cash flow from financing activities Net increase/(decrease) in cash held Net foreign exchange differences Cash and Cash Equivalents At 1 July Cash and Cash Equivalents At 30 June 65,065 (27,521) - (12,413) (6,706) 3,793 22,218 25 (40,171) 41,847 (20,000) (1,000) 48,082 739 (26,283) - - (4,597) (172,176) (173,534) 127,228 125,865 (12,295) 240,798 89,482 - 147,425 236,907 8 8 The above Consolidated Statement of Cash Flows should be read in conjunction with the accompanying notes. 36,917 (27,965) (3,703) - (2,785) 1,614 4,078 50 - - - - - 500 (32,149) (1,261) (65,000) - (9,937) (107,797) 201,934 - - 201,934 98,215 (507) 49,717 147,425 77 Notes to the Financial Statements For the year ended 30 June 2018 1. Corporate information The consolidated financial report of Cooper Energy Limited (the parent entity) for the year ended 30 June 2018 was authorised for issue in accordance with a resolution of the Directors on 13 August 2018. Cooper Energy Limited is a 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 section 5 of the Directors’ Statutory Report. 2. Summary of significant accounting policies a) 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 and Australian Accounting Standards and other authoritative pronouncements of the Australian Accounting Standards Board. The financial report has also been prepared on a historical cost basis, except for equity instruments measured at fair value through other comprehensive income and derivative financial instruments measured at fair value. Cooper Energy Limited is a for profit Company. The financial report is presented in Australian dollars and all values are rounded to the nearest thousand dollars ($’000) unless otherwise stated under the option available to the Group under ASIC Corporations (Rounding in Financial/Directors’ Reports) Instrument 2016/191. The Group is an entity to which the legislative instrument applies. Significant event and transaction Final Investment Decision for the Sole Gas Project Final Investment Decision (“FID”) for the Sole Gas Project was announced by the Company on 29 August 2017. This was a result of achieving full funding of the Sole Gas Project through a fully underwritten accelerated non-renounceable 2 for 5 entitlement offer and with the execution of a fully underwritten debt finance package. The project involves development of the Sole field to commence supply of gas to south-east Australia in 2019. Declaration of Sole FID fulfilled one of the key conditions for the completion of the agreement with APA Group (discussed below). The achievement of FID also triggered a $20.0 million payment of contingent consideration to Santos Limited. Upon reaching FID, the Sole exploration and evaluation assets were assessed for impairment and subsequently transferred to development due to the technical feasibility and commercial viability of gas production becoming evident in accordance with AASB 6. Completion of the sale of the Orbost Gas Plant The sale of the Orbost Gas Plant to APA Group, originally announced on 27 February 2017, completed on 31 October 2017. As part of the transaction, the Company received $20.0 million which is held in escrow and will be released to the Company upon satisfaction of certain conditions; these funds are shown on the balance sheet as a financial asset. Additionally, on completion the Company was reimbursed by APA Group for certain development costs incurred in respect of the Orbost Gas Plant to the value of $24.4 million. A gain on sale of $21.9 million (net of transaction costs) is recognised in the Consolidated Statement of Comprehensive Income. Refer to Note 6 for further information. Syndicated Facility Agreement and draw down On 29 August 2017 the Company executed a fully underwritten finance package including a senior secured $250.0 million syndicated bank debt facility underwritten by ANZ and Natixis and a senior secured $15.0 million working capital facility provided by ANZ. Additional lender support was provided during the 2018 financial year with ABN AMRO, ING and NAB substituting into the syndicated bank debt facility with ANZ and Natixis. As at 30 June 2018 the Company had drawn $125.9 million of the syndicated bank debt facility. Net of costs of $8.9 million non-current borrowings are $116.9 million on the balance sheet. Refer to note 18 for further information. Assumption of BMG rehabilitation provision During the period, the Company assumed an additional 51% of the rehabilitation provision associated with the legacy oil infrastructure at BMG as a result of entering into deeds of release with three exited parties. As settlement of their liabilities, Cooper Energy received $48.1 million from the exited parties. b) Statement of compliance The financial report complies with Australian Accounting Standards and International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board. (i) Changes in accounting policy and disclosures As at 1 July 2015, Cooper Energy early adopted AASB 9 Financial Instruments (2014). AASB 9 (December 2014) is a new standard which replaces AASB 139 (as amended). This new version supersedes AASB 9 issued in December 2009 (as amended) and AASB 9 (issued in December 2010) and includes a model for classification and measurement, a single, forward-looking ‘expected loss’ impairment model and a substantially- reformed approach to hedge accounting, The impact for Cooper Energy has been outlined in Note 23 of the 2016 Financial Statements. 78 Notes to the Financial Statements For the year ended 30 June 2018 2. Summary of significant accounting policies continued b) Statement of compliance continued The Group’s accounting policies are consistent with those of the previous financial year except for new policies adopted from 1 July 2017 as follows: AASB 2016-1 Summary Amendments to Australian Accounting Standards – Recognition of Deferred Tax Assets for Unrealised Losses [AASB 112] This Standard amends AASB 112 Income Taxes (July 2004) and AASB 112 Income Taxes (August 2015) to clarify the requirements on recognition of deferred tax assets for unrealised losses on debt instruments measured at fair value. Application Date of the Standard 1 January 2017 Application Date for Group 1 July 2017 Impact on Group Financial report The adoption of this standard did not have a material impact on the Group. AASB 2016-2 Summary Amendments to Australian Accounting Standards – Disclosure Initiative: Amendments to AASB 107 The amendments to AASB 107 Statement of Cash Flows are part of the IASB’s Disclosure Initiative and help users of financial statements better understand changes in an entity’s debt. The amendments require entities to provide disclosures about changes in their liabilities arising from financing activities, including both changes arising from cash flows and non-cash changes (such as foreign exchange gains or losses). Application Date of the Standard 1 January 2017 Application Date for Group 1 July 2017 Impact on Group Financial report Additional disclosures have been included in note 8. AASB 2017-2 Summary Amendments to Australian Accounting Standards – Further Annual Improvements 2014-2016 Cycle This Standard clarifies the scope of AASB 12 Disclosure of Interests in Other Entities by specifying that the disclosure requirements apply to an entity’s interests in other entities that are classified as held for sale or discontinued operations in accordance with AASB 5 Non-current Assets Held for Sale and Discontinued Operations. Application Date of the Standard 1 January 2017 Application Date for Group 1 July 2017 Impact on Group Financial report The adoption of this standard did not have a material impact on the Group. 79 2. Summary of significant accounting policies continued b) Statement of compliance continued (ii) Accounting standards and interpretations issued but not yet effective The accounting standards and interpretations that have recently been issued or amended but are not yet effective and have not been adopted by the Group for the annual reporting period ending 30 June 2018, are outlined below: AASB 15 Summary Revenue from Contracts with Customers In October 2015, the AASB issued AASB 15 Revenue from Contracts with Customers, which replaces AASB 111 Construction Contracts, AASB 118 Revenue and related Interpretations (AASB Interpretation 13 Customer Loyalty Programmes, AASB 15 Agreements for the Construction of Real Estate, IFRIC 18 Transfers of Assets from Customers and AASB Interpretation 131 Revenue—Barter Transactions Involving Advertising Services). The core principle of AASB 15 is that an entity recognises revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. An entity recognises revenue in accordance with that core principle by applying the following steps: (a) Step 1: Identify the contract(s) with a customer (b) Step 2: Identify the performance obligations in the contract (c) Step 3: Determine the transaction price (d) Step 4: Allocate the transaction price to the performance obligations in the contract (e) Step 5: Recognise revenue when (or as) the entity satisfies a performance obligation Early application of this standard is permitted. AASB 2014-5 incorporates the consequential amendments to a number Australian Accounting Standards (including Interpretations) arising from the issuance of AASB 15. Application Date of the Standard 1 January 2018 Application Date for Group 1 July 2018 Impact on Group Financial report At this point the Company has assessed individual contracts, which has indicated the adoption of the standard is not expected to have a material impact. The Company will apply the full retrospective approach on transition and there will be no adjustment to profit and loss. Additional disclosures on contract details and performance obligations will be required and minor presentation changes of amounts in the Statement of Comprehensive Income will arise. AASB 2014-10 Summary Amendments to Australian Accounting Standards – Sale or Contribution of Assets between an Investor and its Associate or Joint Venture AASB 2014-10 amends AASB 10 Consolidated Financial Statements and AASB 128 to address an inconsistency between the requirements in AASB 10 and those in AASB 128 (August 2011), in dealing with the sale or contribution of assets between an investor and its associate or joint venture. The amendments require: (a) a full gain or loss to be recognised when a transaction involves a business (whether it is housed in a subsidiary or not); and (b) a partial gain or loss to be recognised when a transaction involves assets that do not constitute a business, even if these assets are housed in a subsidiary. AASB 2014-10 also makes an editorial correction to AASB 10. AASB 2017-5 further defers the effective date of the amendments made in AASB 2014-10 to periods beginning on or after 1 January 2022. Application Date of the Standard 1 January 2022 Application Date for Group 1 July 2022 Impact on Group Financial report The adoption of this standard in the current format is not expected to have a material impact on the Group. 80 Notes to the Financial StatementsFor the year ended 30 June 20182. Summary of significant accounting policies continued b) Statement of compliance continued AASB 2016-5 Summary Classification and Measurement of Share-based Payment Transactions This standard amends to AASB 2 Share-based Payment, clarifying how to account for certain types of share-based payment transactions. The amendments provide requirements on the accounting for: • The effects of vesting and non-vesting conditions on the measurement of cash-settled share-based payments • Share-based payment transactions with a net settlement feature for withholding tax obligations • A modification to the terms and conditions of a share-based payment that changes the classification of the transaction from cash-settled to equity-settled Application Date of the Standard 1 January 2018 Application Date for Group 1 July 2018 Impact on Group Financial report The adoption of this standard is not expected to have a material impact on the Group. AASB 2017-1 Amendments to Australian Accounting Standards – Transfers of Investments Property, Annual Improvements 2014-2016 Cycle and Other Amendments Summary The amendments clarify certain requirements in: • AASB 1 First-time Adoption of Australian Accounting Standards –deletion of exemptions for first- time adopters and addition of an exemption arising from AASB Interpretation 22 Foreign Currency Transactions and Advance Consideration • AASB 12 Disclosure of Interests in Other Entities – clarification of scope • AASB 128 Investments in Associates and Joint Ventures – measuring an associate or joint venture at fair value • AASB 140 Investment Property – change in use. Application Date of the Standard 1 January 2018 Application Date for Group 1 July 2018 Impact on Group Financial report The adoption of this standard is not expected to have a material impact on the Group. 81 Notes to the Financial StatementsFor the year ended 30 June 20182. Summary of significant accounting policies continued b) Statement of compliance continued AASB 16 Summary Leases The key features of AASB 16 are as follows: Lessee accounting • Lessees are required to recognise assets and liabilities for all leases with a term of more than 12 months, unless the underlying asset is of low value. • A lessee measures right-of-use assets similarly to other non-financial assets and lease liabilities similarly to other financial liabilities. • Assets and liabilities arising from a lease are initially measured on a present value basis. The measurement includes non-cancellable lease payments (including inflation-linked payments), and also includes payments to be made in optional periods if the lessee is reasonably certain to exercise an option to extend the lease, or not to exercise an option to terminate the lease. • AASB 16 contains disclosure requirements for lessees. Lessor accounting • AASB 16 substantially carries forward the lessor accounting requirements in AASB 117. Accordingly, a lessor continues to classify its leases as operating leases or finance leases, and to account for those two types of leases differently. • AASB 16 also requires enhanced disclosures to be provided by lessors that will improve information disclosed about a lessor’s risk exposure, particularly to residual value risk. AASB 16 supersedes: (a) AASB 117 Leases (b) Interpretation 4 Determining whether an Arrangement contains a Lease (c) SIC-15 Operating Leases—Incentives (d) SIC-27 Evaluating the Substance of Transactions Involving the Legal Form of a lease The new standard will be effective for annual periods beginning on or after 1 January 2019. Early application is permitted, provided the new revenue standard, AASB 15 Revenue from Contracts with Customers, has been applied, or is applied at the same date as AASB 16. Application Date of the Standard 1 January 2019 Application Date for Group 1 July 2019 Impact on Group Financial report The Group is still assessing the impact of this standard. AASB Interpretation 22 Foreign Currency Transactions and Advance Consideration Summary The Interpretation clarifies that in determining the spot exchange rate to use on initial recognition of the related asset, expense or income (or part of it) or on the derecognition of a non-monetary asset or non-monetary liability relating to advance consideration, the date of the transaction is the date on which an entity initially recognises the non-monetary asset or non-monetary liability arising from the advance consideration. If there are multiple payments or receipts in advance, then the entity must determine a date of the transactions for each payment or receipt of advance consideration. Application Date of the Standard 1 January 2018 Application Date for Group 1 July 2018 Impact on Group Financial report The adoption of this standard is not expected to have a material impact on the Group. 82 Notes to the Financial StatementsFor the year ended 30 June 20182. Summary of significant accounting policies continued b) Statement of compliance continued AASB Interpretation 23 Uncertainty over Income Tax Treatments Summary The Interpretation clarifies the application of the recognition and measurement criteria in IAS 12 Income Taxes when there is uncertainty over income tax treatments. The Interpretation specifically addresses the following: • Whether an entity considers uncertain tax treatments separately • The assumptions an entity makes about the examination of tax treatments by taxation authorities • How an entity determines taxable profit (tax loss), tax bases, unused tax losses, unused tax credits and tax rates • How an entity considers changes in facts and circumstances. Application Date of the Standard 1 January 2019 Application Date for Group 1 July 2019 Impact on Group Financial report The adoption of this standard is not expected to have a material impact on the Group. The Group has not early adopted any other standard, interpretation or amendment that has been issued but is not yet effective. c) Basis of consolidation The consolidated financial statements are those of the consolidated entity, comprising Cooper Energy Limited (“the parent entity”) and its subsidiaries (“the Group”). The financial statements of subsidiaries are prepared for the same reporting period as the parent entity, using consistent accounting policies. Adjustments are made to bring into line any dissimilar accounting policies that may exist. 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 control is transferred to the Group and cease to be consolidated from the date on which control is transferred out of the Group. d) Business combinations and asset acquisitions Business combinations Business combinations are accounted for using the acquisition method. The cost of 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 assumed for appropriate classification and designation in accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date. This includes the separation of embedded derivatives in host contracts by the acquiree. 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 either in profit or loss or as a change to other comprehensive income. 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. Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred and the amount recognised for non- controlling interest over the net identifiable assets acquired and liabilities assumed. If this consideration is lower than the fair value of the net assets of the subsidiary acquired, the difference is recognised in profit or loss. After initial recognition, goodwill is measured at cost less any accumulated impairment losses. For the purpose of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Group’s cash-generating units that are expected to benefit from the combination, irrespective of how those other assets or liabilities had been allocated by the acquiree. Where goodwill forms part of the cash generating unit and part of the operation within that unit is disposed of, the goodwill associated with the operation disposed of is included in the carrying amount of the operation when determining the gain or loss on disposal of the operation. Goodwill disposed of in this circumstance is measured based on the relative values of the operation disposed of and the portion of the cash- generating unit retained. Asset acquisitions 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 acuqisition. Under this method transaction costs are capitalised to the asset and not expensed. 83 Notes to the Financial StatementsFor the year ended 30 June 20182. Summary of significant accounting policies continued e) Joint arrangements The Group has interests in arrangements that are controlled jointly. A joint arrangement is either a joint operation or a joint venture. The Group has a number of 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. Currently the Group does not have any interests in joint ventures. 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 f) Foreign currency The functional and presentation currency of the Company is Australian dollars. Translation of foreign currency transactions 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. Translation of the financial result of foreign operations An entity’s functional currency is the currency of the primary economic environment in which the entity, or a significant component of the entity, operates. g) Investments Equity instruments at fair value through other comprehensive income Investments are classified as equity instruments at fair value through other comprehensive income based on an election made at inception and are initially recognised at fair value plus any directly attributable transaction costs. The classification depends on the purpose for which the investments were acquired. After initial recognition, investments are remeasured to fair value. Changes in the fair value of equity investments are recognised as a separate component of equity. The equity reserve will never be recycled through profit or loss. Any dividends received are reflected in profit or loss. For investments that are actively traded in organised financial markets, fair value is determined by reference to stock exchange quoted market bid prices at the close of business on the Consolidated Statement of Financial Position date. Where investments are not actively traded, fair value is established by using other market accepted valuation techniques. Investments in associates An associate is an entity over which the Group has significant influence. Investments in associates are initially recognised at cost. Any surplus over the Group’s share in the associates net assets on acquisition is accounted for as goodwill; any deficit is treated as an accounting gain and recognise immediately in the income statement. After initial recognition, the Group recognises its share of the associate’s profit or loss. h) Revenue and cost recognition Revenue is recognised and measured at fair value of consideration received or receivable to the extent that it is probable that the economic benefits will flow to the Group and the revenue can be reliably measured. The following specific recognition criteria must also be met before revenue is recognised: Revenues and costs from production sharing contracts Revenue earned and production costs incurred from a production sharing contract are recognised when title to the product passes to the customer and is based upon the Group’s share of sales and costs relating to oil production that are allocated to the Group under the contract. Interest revenue Interest revenue is recognised as interest accrues using the effective interest rate, which 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. Joint venture fees Joint venture fees are in respect of the Group’s parent’s ability to recover overhead costs relating to operated activities. Joint venture fees include overhead recoveries on operated activities, parent Company overheads, operator overhead allowances and other indirect charges. Revenue is recognised when the Group’s right to receive payment is established or services are rendered. 84 Notes to the Financial StatementsFor the year ended 30 June 20182. Summary of significant accounting policies continued i) Depreciation and amortisation Oil and gas assets are amortised on the Units of Production basis using the latest approved estimate of Proved and Probable (2P) Reserves. Amortisation is charged only once production has commenced. No amortisation is charged on areas under development where production has not commenced. Depreciation on property plant and equipment is calculated at between 7.5% and 37.5% per annum using the diminishing value method over their estimated useful lives. j) Employee benefits Provision is made for employee benefits accumulated as a result of employees rendering services up to the end of the reporting period. These benefits included wages and salaries, including non-monetary benefits and annual leave. Liabilities 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 general provisions for long service leave are 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 is set out in the Remuneration Report. k) Share based payments The Group provides benefits to employees (including Executive Directors) 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. 85 Notes to the Financial StatementsFor the year ended 30 June 20182. Summary of significant accounting policies continued l) Leases 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. Finance leases, which transfer to the Group substantially all the risks and benefits incidental to ownership of the leased item, are capitalised at the inception of the lease at the fair value of the leased asset or, if lower, at the present value of the minimum lease payments. Lease payments are apportioned between the finance charges and reduction of the lease liability so as to achieve a constant rate of interest on the remaining balance of the liability. Finance charges are recognised as an expense in profit or loss. Capitalised lease assets are depreciated over the shorter of the estimated useful life of the asset and the lease term if there is no reasonable certainty that the Group will obtain ownership by the end of the lease term. Operating lease payments are recognised as an expense in the Consolidated Statement of Comprehensive Income on a straight-line basis over the lease term. m) Income tax 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. The tax rates and tax laws used to compute the amount are those that are enacted or substantively enacted by the Consolidated Statement of Financial Position date. Deferred income tax is provided on all temporary differences at the Consolidated Statement of Financial Position date between the tax bases of assets and liabilities and their carrying amounts for financial reporting purposes. Deferred income tax liabilities are recognised for all taxable temporary differences except: • when the deferred income tax liability arises from the initial recognition of goodwill or of an asset or liability in a transaction that is not a business combination and that, at the time of the transaction, affects neither the accounting profit nor taxable profit or loss; or • when 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, except: • when the deferred income tax asset relating to the deductible temporary difference arises from the initial recognition of an asset or liability in a transaction that is not a business combination and, at the time of the transaction, affects neither the accounting profit nor taxable profit or loss; or • when the deductible temporary difference is associated with investments in subsidiaries, associates or interest in joint ventures, in which case a deferred tax asset is only recognised to the extent that it is probable that the temporary difference will reverse in the foreseeable future and taxable profit will be accessible against which the temporary difference can be utilised. Future taxable profits are estimated by Board approved internal budgets and forecasts. The carrying amount of deferred income tax assets is reviewed at each Consolidated Statement of Financial Position 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 assessed at each Consolidated Statement of Financial Position 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. Where allowable by initial recognition exemptions, deferred tax assets and deferred tax liabilities that arise on acquisition are netted off against each other. 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 Consolidated Statement of Financial Position 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. n) Other taxes Goods and Services Taxes (“GST”) Revenues, expenses and assets are recognised net of the amount of Goods and Services Taxes (“GST”) except:- • where the GST incurred on a purchase of goods and services is not recoverable from the taxation authority, in which case the GST is recognised as part of the cost of acquisition of the asset or as part of the expense item as applicable; and • receivables and payables are stated with the amount of GST included. The net amount of GST recoverable from, or payable to, the taxation authority is included as part of receivables or payables in the Consolidated Statement of Financial Position. 86 Notes to the Financial StatementsFor the year ended 30 June 20182. Summary of significant accounting policies continued n) Other taxes continued 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. Commitments and contingencies are disclosed net of the amount of GST recoverable from, or payable to, the taxation authority. 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. o) Exploration and evaluation expenditure Exploration and evaluation expenditure includes costs incurred in the search for hydrocarbon resources and determining its commercial viability in each identifiable area of interest. Exploration and evaluation expenditure is accounted for in accordance with the successful efforts method and is capitalised to the extent that: i. 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, will comprise 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. A regular review is undertaken of each area of interest to determine the appropriateness of continuing to carry forward costs in relation to that area of interest. Where an ownership interest in an exploration and evaluation asset is exchanged for another, the transaction is recognised by reference to the carrying value of the original interest. Any cash consideration paid, including transaction costs, is accounted for as an acquisition of exploration and evaluation assets. Any cash consideration received, net of transaction costs, is treated as a recoupment of costs previously capitalised with any excess accounted for as a gain on disposal of non-current assets. Where a discovered oil or gas field enters the development phase the accumulated exploration and evaluation expenditure is transferred to oil and gas assets. p) Oil and gas assets 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. 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 during the financial period in which they are incurred. q) Provision for restoration The Group records the present value of its share of the estimated cost to restore operating locations. 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 on an annual basis. When the liability is recorded the carrying amount of the production or exploration asset is increased by the restoration costs and are depreciated over the producing life of the asset. 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 producing life of the asset. Where it is not appropriate to recognise an asset, changes will go through profit or loss. Any change in the discount rate is applied prospectively. These estimated costs, whilst based on anticipated technological and legal requirements, assume no significant changes will occur in relevant State, Federal and International legislation. 87 Notes to the Financial StatementsFor the year ended 30 June 20182. Summary of significant accounting policies continued r) Property, plant and equipment Property, plant and equipment are stated at historical cost less accumulated depreciation and any accumulated impairment losses. 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. All other repairs and maintenance are charged to the Consolidated Statement of Comprehensive Income during the financial period in which they are incurred. The assets’ residual values and useful lives are reviewed, and adjusted if appropriate, at each Consolidated Statement of Financial Position date. Gains and losses on disposals are determined by comparing proceeds with the carrying amount. These are included in the statement of comprehensive income. An item of property, plant and equipment is de-recognised upon disposal or when no further future economic benefits are expected from its use. Any gains or losses arising on de-recognition of the asset (calculated as the difference between the net disposal proceeds and the net carrying amount of the asset) is included in the statement of comprehensive income in the period the asset is de-recognised. s) Impairment of non-current assets The carrying values of non-current assets, including, property, plant and equipment and oil and gas assets are reviewed for impairment at each reporting date, with recoverable amount being estimated when events or changes in circumstances indicate that the carrying value may be impaired. The recoverable amount of non-current assets is the higher of fair value less cost to sell and value in use. An impairment loss is recognised for the amount by which the asset or cash generating unit’s carrying amount exceeds its recoverable amount. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows (cash generating units). In assessing value-in-use, 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. Where the recoverable amount is based on the fair value less cost to sell the inputs are consistent with the level 3 fair value hierarchy. Further details on the significant judgements used in impairment testing of non-current assets are in note 2 bb (ii). t) Cash and cash equivalents Cash and short term deposits in the Consolidated Statement of Financial Position comprise cash at bank and short term deposits generally with an original maturity of three months or less. For the purposes of the Statement of Cash Flows, cash and cash equivalents includes cash on hand and in banks, and money market investments readily convertible to cash within 90 days from date of investment, net of outstanding bank overdrafts. Cash held in escrow with associated restrictions whereby the Company cannot use that cash for operational purposes as it deems appropriate is classified as a financial asset and not as cash and cash equivalents. u) Trade and other receivables Trade receivables, which generally have 30 to 90 day terms, are recognised and carried at original invoice amount less an allowance for any uncollectible amounts. An allowance for doubtful debts is made in accordance with the expected credit loss method. An allowance for doubtful debts is raised at an amount equal to the lifetime expected credit losses if the credit risk on the financial instrument has increased significantly since initial recognition. If the credit risk has not increased significantly since initial recognition, the loss allowance is recognised at an amount equal to the lifetime expected credit losses. Bad debts are written off when identified. v) Inventory Inventories are carried at the lower of their cost or net realisable value. Inventories held by the Group are in respect of stores and spares involved in drilling operations. w) Trade and other payables Trade payables and other payables are carried at amortised costs and represent liabilities for goods and services provided to the Group prior to the end of the financial year that are unpaid and arise when the Group becomes obliged to make future payments in respect of the purchase of these goods and services. x) Provisions Provisions are recognised when the Group has a legal or constructive obligation to make a future sacrifice of economic benefits to other entities 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. Provisions are not recognised for future operating losses. Where there are a number of similar obligations, the likelihood that an outflow will be required in settlement is determined by considering the class of obligations as a whole. A provision is recognised even if the likelihood of an outflow with respect to any one item included in the same class of obligations may be small. 88 Notes to the Financial StatementsFor the year ended 30 June 20182. Summary of significant accounting policies continued y) Contributed equity Issued and paid up capital is recognised as the fair value of the consideration received by the Group. 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. z) Earnings per share Basic earnings per share are calculated as net profit attributable to members divided by the weighted average number of ordinary shares. Diluted earnings per share is calculated as net profit attributable to members 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. aa) Derivative financial instruments 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 other comprehensive income may be designated as hedging instruments in cash flow hedges. Cash flow hedges The Group uses oil price options as hedges of its exposure to commodity price risk and 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 if its designation as a hedge is revoked, 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. bb) Significant accounting judgements, estimates and assumptions (i) Significant accounting judgements In the process of applying the Group’s accounting policies, management has made the following judgements, apart from those involving estimations, which have the most significant effect on the amounts recognised in the financial statements: 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. Taxation The Group’s accounting policy for taxation requires management’s judgement 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 (Imposition – General) Act 2011, 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. 89 Notes to the Financial StatementsFor the year ended 30 June 20182. Summary of significant accounting policies continued continued bb) Significant accounting judgements, estimates and assumptions continued (i) Significant accounting judgements continued 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. Operating lease commitments The Group has entered into commercial property leases. The Group has determined that is does not retain any of the significant risks and rewards of ownership of these properties and has thus classified the leases as operating leases. (ii) Significant accounting estimates and assumptions The carrying amounts of certain assets and liabilities are often determined based on estimates and assumptions of future events. The key estimates and assumptions that have a significant risk of causing a material adjustment to the carrying amounts of certain assets and liabilities within the next annual reporting period are: 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 Company’s Hydrocarbon Guidelines (www.cooperenergy.com.au/policies). 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. Impairment of capitalised exploration and evaluation expenditure 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 become 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. 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 testing at 30 June 2018 showed impairment was required to be recognised on the Group’s exploration and evaluation expenditure as set out in note 13. Impairment of oil and gas assets and property, plant & equipment The Group reviews the carrying amount of oil and gas assets and property, plant & equipment at each reporting date starting with analysis of any indicators of impairment. Where indicators of impairment are present, the Group will test whether the cash generating unit’s recoverable amount exceeds its carrying amount. The Group performs a value in use calculation of an asset or cash generating unit using a discounted cash flow model. 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, capital expenditure for any development required to produce 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 oil price assumptions (real) are US$65/bbl for FY19, US$67/bbl for FY20 and US$68/bbl long term. The Group’s gas price assumptions are based on contracted gas prices for contracted gas volumes, and the Group’s view of future uncontracted gas price assumptions based on market data available, and assessments of the South-east Australia gas market supply and demand. 90 Notes to the Financial StatementsFor the year ended 30 June 20182. Summary of significant accounting policies continued continued bb) Significant accounting judgements, estimates and assumptions continued (ii) Significant accounting estimates and assumptions continued Discount rates applied in the net present value calculation of the value in use are derived from the weighted average cost of capital. The Group applied a pre-tax real discount rate of 11.7%. The sensitivity of the impairment models to these assumptions is tested as part of this process and shows that the models are most sensitive to management’s assumptions relating to production, commodity prices and discount rates. In the event that future circumstances vary from the assumptions used in the impairment assessment, the recoverable amount of the Groups assets or cash generating units could change materially and result in an impairment loss. Impairment testing at 30 June 2018 showed no impairment was required to be recognised with respect to the Group’s oil and gas assets and property, plant and equipment. Provisions for decommissioning and 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 well’s life. In determining an appropriate level of provision consideration is given to the expected future costs to be incurred, the timing of these expected future costs (largely dependent on the life of the well), and the estimated future level of inflation. The ultimate cost of decommissioning and restoration is uncertain and costs can vary in response to many factors including changes to the relevant legal requirements, the emergence of new restoration techniques or experience at other wells. 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 level of provisioning required, which would in turn impact future financial results. Share-based payments transactions 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 detailed in Note 2(k). 3. Segment reporting Identification of reportable segments and types of activities Following the completion of the Victorian gas asset acquisition in the second half of 2017, the Group identified its operating segments to be Cooper Basin, South-east Australia (based on the nature and geographic location of the assets) and the Corporate and Discontinued operating segments. This forms the basis that the Group reports internally 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. The comparative disclosures have been restated to be on a consistent basis as the new segments. Other prospective opportunities outside of these segments are also considered from time to time and, if they are secured, will then be attributed to the basin where they are located. The following are the current segments: Cooper Basin Exploration and evaluation of oil and gas and production and sale of crude oil in the Company’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 Origin Energy Resources Limited. South-east Australia The South-east Australia segment primarily consists of the Sole Gas Project, Manta Gas Project and gas production from the Company’s interest in the operated Casino Henry and non-operated Minerva 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 Business Unit The Corporate Business Unit includes the revenue and costs associated with the running of the business and includes items which are not directly allocable to the other segments. Discontinued Operations Discontinued operations consist of the Company’s former interests in Indonesia and Tunisia which have been sold or withdrawn from at 30 June 2017. 91 Notes to the Financial StatementsFor the year ended 30 June 20183. Segment reporting continued Accounting policies and inter-segment transactions The accounting policies used by the Group in reporting segments internally is the same as those contained in Note 2 to the accounts and in the prior period. The following table presents revenue and segment results for reportable segments: Segments Cooper Basin South-east Australia Corporate Continuing Operations Total Discontinued Operations Total Consolidated $’000 $’000 $’000 $’000 $’000 $’000 Year ended 30 June 2018 Revenue 26,602 40,850 Other income and revenue - - Total consolidated revenue 26,602 40,850 - 4,933 4,933 - (604) 67,452 4,933 72,385 (604) (2,716) (16,873) (2,735) (44) (696) (775) 21,934 (324) (4,916) 236 34 (2,642) (16,881) (1,994) (11,520) (850) 31,019 (3,053) (13,820) (109) (2,626) (2,716) (44) - (775) 21,934 - (4,916) - 34 - (9,712) - - - - - - - - - - (324) - 236 - (2,642) - - (11,520) - - - - (696) - - - - - - - (7,169) (1,994) - (850) 12,731 12,731 5,168 18,978 11,046 28,209 (9,921) 28,209 210,810 284,598 482,441 (9,921) 156,897 513,181 35,634 31,019 372,875 816,757 529,121 - - - - - - - - - - - - - - - - - - - - - - - - - 67,452 4,933 72,385 (604) (2,716) (16,873) (2,735) (44) (696) (775) 21,934 (324) (4,916) 236 34 (2,642) (16,881) (1,994) (11,520) (850) 31,019 4,781 (8,789) 27,011 372,875 816,757 529,121 Depreciation of property, plant and equipment Amortisation of property, plant and equipment Amortisation of oil and gas assets Accretion on rehabilitation provision Accretion on success fee liability Impairment Care & maintenance Gain on sale of subsidiary Write-off of fixed asset Restoration expense Fair value movement on oil price derivatives Fair value adjustment on success fee Share based payments Production expenses Royalties Other expenses Exploration costs written off Segment result Income tax Petroleum Resource Rent Tax Net profit/(loss) Segment liabilities Segment assets Non-Current Assets 92 Notes to the Financial StatementsFor the year ended 30 June 2018 3. Segment reporting continued Segments Cooper Basin South-east Australia Corporate Continuing Operations Total Discontinued Operations Total Consolidated $’000 $’000 $’000 $’000 $’000 $’000 Year ended 30 June 2017 Revenue 15,513 19,135 Other income and revenue - - Total consolidated revenue 15,513 19,135 - - - (595) (2,083) (7,120) (92) (2,420) 34,648 1,614 36,262 (235) (595) 4,481 - 4,481 (56) - 39,129 1,614 40,743 (291) (595) (9,203) (59) (9,262) Depreciation of property, plant and equipment Amortisation of property, plant and equipment Amortisation of oil and gas assets Accretion on rehabilitation provision Accretion on success fee liability Impairment Care & maintenance Share of loss in associate Restoration expense Fair value adjustment on success fee Share based payments Production expenses Royalties Gain on sale of subsidiary Other expenses Exit provision Exploration costs written off Segment result Income tax Petroleum Resource Rent Tax Net profit/(loss) Segment liabilities Segment assets Non-Current Assets - 1,614 1,614 (235) - - - - - - (533) - - (2,272) - - - - - (2,512) (43) - (1,629) (533) (1,226) 58 (2,272) (9,198) (1,062) - - (1,577) (7,035) (43) - (1,629) - (1,226) 58 - (3,036) - - - - - - - - - - - - (6,162) (1,062) - - - (1,577) 4,537 4,537 6,526 16,718 12,684 (13,270) (13,270) 3,124 (14,696) 3,124 163,492 316,006 283,981 (14,696) 33,825 159,920 8,684 (7,035) 203,843 492,644 305,349 - - (1,020) - - - - (1,780) (672) 1,395 (360) (4,031) (242) (2,344) (2,344) 3,754 - - 2018 $’000 67,452 - 67,452 (2,512) (43) (1,020) (1,629) (533) (1,226) 58 (2,272) (10,978) (1,734) 1,395 (13,630) (4,031) (1,819) (9,379) 4,665 (7,598) (12,312) 207,597 492,644 305,349 2017 $’000 34,648 4,481 39,129 Revenue from external customers by geographical location of production Australia Indonesia1 Total revenue Revenue from three customers amounted to $24,365,000, $10,357,000 and $5,084,000 respectively in the South-east Australia segment and $21,842,000 from one customer in the Cooper Basin segment. In 2017, revenue from two customers amounted to $14,296,000 in the South-east Australia segment and $15,127,000 in the Cooper Basin segment. 1. Classified as revenue from discontinued operations in the prior year. 93 Notes to the Financial StatementsFor the year ended 30 June 2018 4. Revenues and expenses from continuing operations Profit before income tax expense includes the following revenues and expenses whose disclosure is relevant in explaining the performance of the entity: Revenues from continuing operations Oil sales Gas sales Total revenue from operations Other revenue Interest revenue Gain on movement of consideration receivable Gain on derecognition of associate Joint venture fees Total other revenue Cost of sales Production expenses Royalties Amortisation of oil and gas assets Amortisation of property, plant and equipment Total cost of sales Finance costs Accretion of rehabilitation provisions Accretion of success fee liability Interest expense Capitalised interest Total finance costs Other expenses Depreciation of property, plant and equipment General administration (includes employee benefits and lease payments) Care and maintenance Write-off of fixed asset Restoration expense Shae of associate’s loss Fair value adjustment of success fee liability Fair value movement on oil price derivatives Realised and unrealised foreign currency translation gain/(loss) Total other expenses Employee benefits expense (gross) Director and employee benefits Share based payments Superannuation expense Total employee benefits expense Lease payments Consolidated 2018 $’000 26,602 40,850 67,452 2017 $’000 15,738 18,910 34,648 4,049 1,331 531 353 - 4,933 (16,881) (1,994) (16,873) (2,716) (38,464) (2,735) (44) (3,394) 3,394 (2,779) (604) (14,797) (775) (324) (4,916) - 34 236 635 - - 283 1,614 (9,198) (1,062) (9,203) (595) (20,058) (2,512) (43) - - (2,555) (235) (15,388) (1,629) - (1,226) (533) 58 - (154) (20,511) (19,107) (12,536) (2,642) (657) (15,835) (8,172) (2,272) (440) (10,884) Minimum lease payment – operating lease (839) (352) 94 Notes to the Financial StatementsFor the year ended 30 June 20185. Income tax The major components of income tax expense are: Consolidated Statement of Comprehensive Income Current income tax Adjustments in respect of prior year income tax Deferred income tax Origination and reversal of temporary differences Over provision in respect of prior year income tax Income tax benefit Current royalty tax Current year Adjustments in respect of prior year income tax Deferred royalty tax Origination and reversal of temporary differences Total royalty tax expense Numerical reconciliation between tax expense and pre-tax net profit Accounting profit/(loss) before tax from continuing operations Income tax using the domestic corporation tax rate of 30% (2017: 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 Other Total Royalty related tax expense Income tax expense Income tax recognised in other comprehensive income Deductible equity costs Fair value movement on derivative financial instruments Income tax using the domestic corporation tax rate of 30% (2017: 30%) Consolidated 2018 $’000 2017 $’000 - - 5,784 (1,003) 4,781 4,781 (1,372) 1,458 (38) (38) 4,824 - 4,824 4,786 (6,117) - 86 (6,117) (8,875) (8,875) (8,789) 31,019 (9,306) 6,044 6,582 (749) (1,003) 3,107 106 4,781 (8,789) (4,008) 1,599 (92) 1,507 (1,481) (1,481) (7,598) (7,035) 2,111 - - (54) (38) 2,279 488 4,786 (7,598) (2,812) - (369) (369) 95 Notes to the Financial StatementsFor the year ended 30 June 2018 5. Income tax continued Cooper Energy Limited and its 100% owned Australian resident subsidiaries formed a tax consolidated Group. Cooper Energy Limited is 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. Cooper Energy Limited formally notified the Australian Tax Office of its adoption of the tax consolidation regime when lodging its 30 June 2003 consolidated tax return. 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 2018, there are no unrecognised temporary differences associated with the Group’s investments in subsidiaries or joint ventures, as the Group has no liability for additional taxation should unremitted earnings be remitted (2017 $nil). Franking Tax Credits At 30 June 2018 the parent entity had franking tax credits of $42,856,152 (2017: $42,856,152). The fully franked dividend equivalent is $142,852,840 (2017 $142,852,840). PRRT Cooper Energy Limited has recognised a Deferred Tax Liability for Petroleum Resource Rent Tax (PRRT) of $10,356,000 (2017: $1,481,000) relating to PRRT on the Company’s producing gas assets. The Company has not recognised a Deferred Tax Asset for PRRT of $39,037,000 (2017: $29,386,000). This is in respect of the Company’s Cooper Basin oil producing assets on the basis that it has a significant level of undeducted expenditure and nil PRRT payments projected in the future and the Sole Gas Project. Income Tax Losses (a) Revenue Losses Cooper Energy has recognised a Deferred Tax Asset for the year ended 30 June 2018 of $21,612,000 (2017: $16,275,000). (b) Capital Losses Cooper Energy has not recognised a Deferred Tax Asset for Australian income tax capital losses of $2,998,458 (2017: $62,272,095) 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 during the year to offset the capital gain generated from the sale of the Orbost Gas Plant and the receipt of funds from exited joint venture parties for the BMG abandonment. Consolidated Statement of Financial Position Consolidated Statement of Comprehensive Income 2018 $’000 2017 $’000 2018 $’000 2017 $’000 3,583 16,153 4,082 424 - 2,419 (1,164) 325 (15,828) 15,934 11,851 24 38 (308) 38 1,486 325 3,398 - 38 24,242 18,740 (5,411) 5,247 Deferred income tax from corporate tax Deferred income tax at 30 June relates to the following: Deferred tax liabilities Trade and other receivables Oil and gas assets Exploration and evaluation Other Unrealised currency translation gain 96 Notes to the Financial StatementsFor the year ended 30 June 20185. Income tax continued Deferred tax assets Property, plant & equipment Oil and gas assets Unrealised currency translation gain Trade and other payables Provision for employee entitlements Provisions Other Capital raising costs Tax losses Deferred tax benefit Consolidated Statement of Financial Position Consolidated Statement of Comprehensive Income 2018 $’000 2017 $’000 2018 $’000 2017 $’000 - - - - 1,823 4,602 3,313 3,226 21,612 34,576 - - - 1,199 365 2,488 473 2,255 16,275 23,055 - - - (1,199) 1,459 2,114 3,108 (628) 5,338 10,192 (10) (1,762) (2) 1,199 (210) 1,900 (22) - 8,614 9,707 4,781 14,954 Deferred tax asset from corporate tax 10,334 4,315 Deferred income tax from petroleum resource rent tax Deferred income tax at 30 June relates to the following: Deferred tax liabilities Oil and gas assets 6. Discontinued operations and assets held for sale Orbost Gas Plant 10,356 1,481 8,875 1,481 The sale of the Orbost Gas Plant to APA Group, originally announced on 27 February 2017, completed on 31 October 2017. The plant was sold for consideration of $20.0 million to be held in escrow, which will be released to the Company upon satisfaction of certain conditions; these funds are shown on the balance sheet as a financial asset. Additionally, $24.4 million of costs incurred by the Company in respect of the Orbost Gas Plant were reimbursed by APA. On completion, a gain on sale of $21.9 million was recognised in the Consolidated Statement of Comprehensive Income. Consideration received Transaction costs Net consideration received Value of assets sold Gain on sale Indonesia 2018 $’000 44,352 (2,505) 41,847 19,913 21,934 During 2017, the Company executed a share sale agreement with Bass Oil Company Limited (BAS), the Company’s associate, for the sale of its remaining Indonesian asset, a 55% interest in the Tangai-Sukananti KSO. The Company has agreed to an extension to the settlement terms, with an interest charge payable by BAS on the deferred balance. A receivable of $2.2 million remains on the balance sheet relating to the deferred consideration receivable from Bass Oil Company Limited which will be fully received by June 2019. 97 Notes to the Financial StatementsFor the year ended 30 June 20187. Earnings per share Basic earnings per share amounts are calculated by dividing net profit for the year attributable to ordinary equity holders of the parent by the weighted average of ordinary shares outstanding during the year. Diluted earnings per share amounts are calculated by dividing the net profit attributable to ordinary equity holders of the parent by the weighted average number of ordinary shares outstanding during the year plus the weighted average number of ordinary shares that would be issued on the conversion of all the dilutive potential options into ordinary shares. At 30 June 2018 there exists 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 prior 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. The following reflects the income and share data used in the basic and diluted earnings per share computations: Net profit/(loss) attributable to ordinary equity holders of the parent from continuing operations Weighted average number of ordinary shares for basic earnings per share Weighted average number of ordinary shares adjusted for the effect of dilution1 Basic earnings per share for the period (cents per share) Diluted earnings per share for the period (cents per share) Net profit/(loss) attributable to ordinary equity holders of the parent from continuing and discontinued operations Weighted average number of ordinary shares for basic earnings per share Weighted average number of ordinary shares adjusted for the effect of dilution1 Basic earnings per share for the period (cents per share) Diluted earnings per share for the period (cents per share) Consolidated 2018 $’000 27,011 2018 Thousands 1,506,880 1,529,450 1.8 1.8 2017 $’000 (9,847) 2017 Thousands 683,255 683,255 (1.4) (1.4) Consolidated 2018 $’000 2017 $’000 27,011 (12,312) 2018 Thousands 1,506,880 1,529,450 1.8 1.8 2017 Thousands 683,255 683,255 (1.8) (1.8) 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. 1. The weighted average number of potentially dilutive shares at 30 June 2018 is 1,529,450,000 (2017: 705,291,000), including performance rights and share appreciation rights that have not been achieved and vested at the end of the financial year. 98 Notes to the Financial StatementsFor the year ended 30 June 20188. Cash and cash equivalents and term deposits Current Assets Cash at bank and in hand Short term deposits at banks (i) Total cash and cash equivalents Non-Current Assets Term deposits at bank (ii) Consolidated 2018 $’000 236,907 - 2017 $’000 49,425 98,000 236,907 147,425 16 41 (i) Short term deposits at banks are in Australian dollars and are generally for periods of three months or less and earn interest at money market interest rates. There were no term deposits with a maturity greater than 3 months. (ii) The carrying value of term deposits approximates their fair value. Reconciliation of net profit after tax to net cash flows from operating activities Net profit/(loss) for the Year Adjustments for: Amortisation of oil and gas assets Amortisation of property, plant and equipment Depreciation of property, plant and equipment Exploration and evaluation written off Exit provision Other non-cash movement Impairment of Non-Current Assets Gain on sale of subsidiary Write-off of fixed assets Gain on derecognition of associate Share of loss in associate Share based payments Finance cost Restoration expense Fair value adjustment of success fee liability Gain on movement of consideration receivable Unrealised foreign currency translation (gain)/loss (Increase)/decrease in trade and other receivables (Increase)/decrease in prepayments (Decrease)/increase in deferred taxes (Decrease)/increase in trade and other payables (Decrease)/increase in provisions (Increase)/decrease in held for sale assets Net cash from operating activities Consolidated 2018 $’000 2017 $’000 27,011 (12,312) 16,873 2,716 604 850 153 1,841 696 (21,934) 324 (353) - 2,642 2,779 4,916 (34) (531) (1,385) (11,544) 52 2,856 5,463 (12,135) 358 22,218 2017 $’000 Cash Flows $’000 Other $’000 9,262 595 291 1,819 (3,703) - 1,020 (1,395) - - 533 2,272 2,555 1,226 (58) - 57 (10,474) (507) (5,010) 13,216 559 4,132 4,078 2018 $’000 Reconciliation of liabilities arising from financing activities Interest bearing loans and borrowings Total liabilities from financing activities - - 125,865 125,865 (8,942) (8,942) 116,923 116,923 99 Notes to the Financial StatementsFor the year ended 30 June 20189. Trade and other receivables Current Assets Trade receivables (i) Accrued revenue Related party receivable – joint arrangements Interest receivable Consolidated 2018 $’000 12,604 12,298 2,067 361 27,330 2017 $’000 2,813 7,855 - 210 10,878 (i) Trade receivables are non-interest bearing and are generally on 30-90 days terms. There are no past due or impaired trade receivables and none that have a history of past default. Non-Current Assets Trade receivables Consideration receivable 10. Prepayments Current Assets Bank facility fee Insurance Other Non-Current Assets Insurance 11. Equity instruments Shares at fair value A reconciliation of the movement during the year is as follows:- Opening balance Gain on derecognition of associate Fair value movement Closing balance Consolidated 2018 $’000 11 145 156 Consolidated 2018 $’000 - 1,761 1,000 2,761 - - Consolidated 2018 $’000 2,241 658 353 1,230 2,241 2017 $’000 1,739 1,258 2,997 2017 $’000 79 1,787 36 1,902 911 911 2017 $’000 658 790 - (132) 658 The equity investments consist of two investments and the Group has received no dividends throughout the financial year. 100 Notes to the Financial StatementsFor the year ended 30 June 201812. Oil and Gas assets Reconciliation of carrying amounts at beginning and end of period: Carrying amount at 1 July Additions Transferred from exploration and evaluation Gas assets acquired Amortisation Carrying amount at 30 June Cost Accumulated amortisation & impairment 13. Impairment Impairment of exploration and evaluation assets Cooper Basin Northern Licenses Total Consolidated 2018 $’000 69,402 192,468 149,635 - (16,873) 394,632 447,631 (52,999) 394,632 2017 $’000 5,385 6,530 - 66,690 (9,203) 69,402 105,528 (36,126) 69,402 Consolidated 2018 $’000 696 696 2017 $’000 - - In accordance with the Group’s accounting policies and procedures, the Group performs its impairment testing bi-annually. Exploration and evaluation impairment During the financial year the Company’s exploration assets were assessed for impairment indicators in accordance with AASB 6. Impairment losses were recognised in respect of the Cooper Basin Northern Licenses during the 2018 financial year as a result of no significant work planned in the future and no current commercial development potential. Oil and gas asset impairment At year-end the Company’s oil and gas assets were assessed for impairment indicators in accordance with AASB 136. Following this assessment, notwithstanding that impairment indicators were present, no impairment was recognised on oil and gas assets during the 2018 financial year. 14. Property, plant and equipment Reconciliation of carrying amounts at beginning and end of period: Carrying amount at 1 July Assets acquired Additions Disposals/written off Depreciation Amortisation Transferred to assets held for sale Carrying amount at 30 June Cost Accumulated depreciation & amortisation Consolidated 2018 $’000 3,694 - 2,822 (332) (604) (2,716) - 2,864 8,407 (5,543) 2,864 2017 $’000 708 3,743 2,159 (1) (235) (595) (2,085) 3,694 5,917 (2,223) 3,694 101 Notes to the Financial StatementsFor the year ended 30 June 201815. Exploration and evaluation Reconciliations of the carrying amounts of capitalised exploration at the beginning and end of the financial year are set out below: Carrying amount at 1 July Additions Exploration acquired Unsuccessful exploration wells written off (i) Impairment Transfer to oil and gas assets Carrying amount at 30 June (ii) Consolidated 2018 $’000 2017 $’000 223,331 110,976 26,582 - (850) (696) (149,635) 29,094 84,061 (800) - - 98,732 223,331 (i) Exploration write offs relate to exploration wells that were plugged and abandoned as unsuccessful during the year. (ii) Recoverability is dependent on the successful development and commercial exploration or sale of the respective areas of interest. 16. Trade and other payables Trade payables (i) Hedge payable Contingent bonus consideration (ii) Accruals (iii) Deferred lease incentive Related party payables – joint arrangements (iv) Consolidated 2018 $’000 14,159 - - 39,342 1,459 54,960 4,255 59,215 (i) Trade and other payables are non-interest bearing and are normally settled on 30-90 day terms. (ii) Contingent bonus consideration was payable to Santos Limited on final investment decision on the Sole Gas Project. (iii) Accruals include capital accruals on projects. (iv) Related party payables are accrued expenditure incurred on joint arrangements. 2017 $’000 5,110 22 20,000 29,366 - 54,498 4,022 58,520 2017 $’000 14,584 3,754 850 - Consolidated 2018 $’000 67,651 3,907 730 1,524 73,812 19,188 17. Provisions Current Liabilities Restoration provision Exit penalty provision Employee provisions Other provisions 102 Notes to the Financial StatementsFor the year ended 30 June 201817. Provisions continued Non-Current Liabilities Long service leave provision Restoration provisions Movement in carrying amount of the current restoration provision: Carrying amount at 1 July Restoration provision assumed (i) Restoration expenditure incurred Transferred from non-current provisions Impact of changes in restoration assumptions (ii) Carrying amount at 30 June Movement in carrying amount of the non-current restoration provision: Carrying amount at 1 July Transferred to held for sale Restoration expenditure incurred New provisions recognised (iii) Transferred to current provisions Provision through asset acquisition Increase through accretion Impact of changes in restoration assumptions (ii) Carrying amount at 30 June Consolidated 2018 $’000 610 106,070 106,680 14,584 48,082 (16,367) 21,271 81 2017 $’000 365 99,437 99,802 - - - 14,584 - 67,651 14,584 99,437 - - 13,608 65,202 (9,980) (155) - (21,271) (14,584) - 2,649 11,647 106,070 71,687 2,512 (15,245) 99,437 (i) Relates to the Company’s increased share of the BMG restoration provision on settlement with exited parties as outlined in note 2 a. (ii) Changes in restoration assumptions results from a change in the discount rate and changes in gross cost assumptions. (iii) New provisions recognised is in respect of restoration provisions arising from the drilling of the Sole-3 and Sole-4 wells. The restoration provision is the present value of the Group’s share of the estimated cost to restore operating locations. 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. However, actual restoration costs will ultimately depend upon future market prices for the necessary decommissioning works required that will reflect market conditions and the condition of the site at the time of the restoration. Furthermore, the timing of restoration is likely to depend on when the fields cease to produce at economically viable rates. This, in turn, will depend upon future oil and gas prices, which are inherently uncertain. The discount rate used in the calculation of the provisions as at 30 June 2018 ranged from 2.00% to 2.70% (2017: 2.41%) reflecting a risk free rate that aligns to the date of restoration obligations. 103 Notes to the Financial StatementsFor the year ended 30 June 201818. Interest bearing loans and borrowings Interest bearing loans and borrowings Non-current (bank debt) Total interest bearing loans and borrowings Net of capitalised transaction costs of $8.9 million. Consolidated 2018 $’000 2017 $’000 116,923 116,923 - - In August 2017, Cooper Energy negotiated a A$250 million senior secured Reserve Based Lending Facility, principally to fund the Sole Gas Project, and a senior secured $15 million working capital facility. Borrowings are recognised initially at fair value. 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 then amortised on a straight-line basis 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 received at balance date, is reflected in the balance sheet as a payable. A summary of the Group’s secured facilities is included below. Facility Currency Limit1 Reserve Based Lending Facility Australian dollars $250.0 million (2017: Nil) Utilised amount $125.9 million (2017: Nil) Accounting balance $116.9 million Effective interest rate 6.36% Maturity 2021 – 2024 1. Of the facility limit of $250.0 million, $224.0 million is currently available. Facility Currency Limit Utilised amount1 Accounting balance Effective interest rate Working Capital Facility Australian Dollars $15.0 million Nil (2017: Nil) Nil Nil Maturity Revolving facility 1. As at 30 June 2018, $945,825 has been utilised by way of bank guarantees. 19. Contributed equity and reserves Share capital Ordinary shares Issued and fully paid 104 2018 $’000 2017 $’000 471,837 343,161 Notes to the Financial StatementsFor the year ended 30 June 201819. Contributed equity and reserves continued Capital raising During the period the Group raised $127.8 million (net of costs and tax of $6.2 million) through institutional placements and entitlement offers, 456,221,699 new ordinary shares were issued. Fully paid ordinary shares carry one vote per share and carry the right to dividends. Movement in ordinary shares on issue At 1 July Equity issue Issuance of shares to contractors Issuance of shares for performance rights & share appreciation rights 2018 2017 Thousands $’000 Thousands $’000 1,140,551 343,161 456,222 127,803 - 4,306 - 873 435,186 699,662 630 5,073 137,558 203,940 223 1,440 1,601,079 471,837 1,140,551 343,161 At 30 June Reserves Consolidated At 1 July 2016 Other comprehensive income/(expenditure) Transferred to issued capital Share-based payments At 30 June 2017 (541) Other comprehensive income/(expenditure) Transferred to issued capital Share-based payments - - - At 30 June 2018 (541) Nature and purpose of reserves Consolidation reserve Consolidation reserve $’000 Foreign currency translation reserve $’000 Share based payment reserve $’000 Option premium reserve $’000 Cash flow hedge reserve $’000 Equity instrument reserve $’000 Total $’000 (541) 1,132 7,208 25 (700) (553) 6,571 - - - (1,132) - - - - - - - - (1,440) 2,049 7,817 - (873) 2,642 9,586 - - - 25 - - - 861 (132) (403) - - 161 149 - - - - (685) 1,230 - - (1,440) 2,049 6,777 1,379 (873) 2,642 9,925 25 310 545 The reserve comprises the premium paid on acquisition of minority shareholdings in a controlled entity. Foreign currency translation reserve This reserve is used to record the value of foreign currency movements on retranslation of the net assets of the US dollar functional currency subsidiary. Share based payment reserve This reserve is used to record the value of equity benefits provided to employees 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 mark to market movement in the value of shares held in companies listed on a public exchange. Items in this reserve are never recycled through profit or loss. 105 Notes to the Financial StatementsFor the year ended 30 June 201819. Contributed equity and reserves continued Accumulated Losses Movement in accumulated losses: Balance at 1 July Net profit/(loss) for the year Balance at 30 June Capital Management Consolidated 2018 $’000 2017 $’000 (64,891) 27,011 (37,880) (52,579) (12,312) (64,891) 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. 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. The Group currently has utilised $125.9 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 years ended 30 June 2018 and 30 June 2017. 20. Financial risk management objectives and policies The Group’s principal financial instruments comprise cash and short term deposits, receivables, equity investments, payables and borrowings. Details of the significant accounting policies and methods adopted, including criteria for recognition, the basis of measurement and the basis on which income and expenses are recognised in respect of each financial instrument are disclosed in Note 2 to the financial statements. Other financial assets Current Cash held in escrow Non-Current Escrow proceeds receivable Other financial liabilities Current Derivative financial instruments Derivative financial instruments designated in a hedge relationship Non-Current Success fee financial liability Derivative financial instruments designated in a hedge relationship 106 Consolidated 2018 $’000 2017 $’000 20,171 20,171 20,146 20,146 236 355 591 3,054 177 3,231 - - - - - 114 114 3,044 - 3,044 Notes to the Financial StatementsFor the year ended 30 June 201820. Financial risk management objectives and policies continued Movement in carrying amount of the success fee financial liability: Carrying amount at 1 July Finance cost Fair value adjustment Carrying amount at 30 June Fair value hierarchy Consolidated 2018 $’000 2017 $’000 3,044 3,059 44 (34) 43 (58) 3,054 3,044 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 Company determines whether transfers have occurred between levels in the hierarchy by re-assessing categorisation (based on the lowest level input that is significant to the fair value measurement as a whole) at the end of each reporting period. Set out below is an overview of financial instruments held by the Company, with a comparison of the carrying amounts and fair values as at 30 June 2018: Carrying amount Fair value Level 2018 $’000 2017 $’000 2018 $’000 2017 $’000 Consolidated Financial assets Trade and other receivables Equity instruments Cash held in escrow Escrow proceeds receivable Financial liabilities Trade and other payables Success fee financial liability Derivative financial instruments Derivative financial instruments designated in a hedge relationship Interest bearing loans and borrowings 2 1 2 2 2 3 2 2 2 27,330 13,875 27,330 13,875 2,241 20,171 20,146 59,215 3,054 236 532 658 - - 58,520 3,044 - 114 2,241 20,171 20,146 59,215 3,054 236 532 116,923 - 101,842 The following summarises the significant methods and assumptions used in estimating the fair values of financial instruments: Equity instruments Equity instruments are measured at fair value through other comprehensive income. The fair value of equity instruments is 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. 658 - - 58,520 3,044 - 114 - 107 Notes to the Financial StatementsFor the year ended 30 June 201820. Financial risk management objectives and policies continued Cash held in escrow and escrow proceeds receivable During the period, the Company completed the sale of Orbost Gas Plant to APA Group. A portion of proceeds from the sale is held in escrow, to be released upon certain conditions being satisfied. Additional funds are held in escrow for payments to be made in connection with the Company’s 2018 drilling campaign. Amounts held in escrow are measured at amortised cost and held at the estimated realisable value in the 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 the fair value is obtained from third party valuation reports. Derivative financial instruments Commodity derivatives are also used to manage the Group’s exposure to changes in oil prices and are measured at fair value through profit and loss. The Group has elected not to apply hedge accounting to its commodity derivatives entered into during the 2018 financial year. The use of derivative financial instruments is subject to a set of policies, procedures and limits approved by the Board of Directors. The Group does not trade in derivative financial instruments for speculative purposes. Success fee financial liability The success fee liability is the fair value of the Group’s liability to pay a $5,000,000 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 valuation inputs for the success fee financial liability includes: a probability of 37% that no payment is made and a probability of 63% the payment is made in 2023. The discount rate used in the calculation of the liability as at 30 June 2018 equalled 2.70% (June 2017: 2.41%). 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. 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 Company has established a Risk and Sustainability Committee from 1 July 2017. 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. It is, and has been, throughout the period under review, the Board’s policy that no speculative trading in financial instruments be undertaken. The primary responsibility for the identification and control of financial risks rests with the Managing Director and the Chief Financial Officer, under the authority of the Board. The Board is apprised of these and other risks at Board meetings and agrees any policies that may be implemented to manage any of the risks identified below. Market risk Market risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate because of changes in market prices. Market risk comprises three types of risk: foreign currency risk, commodity price risk and interest rate risk. Financial instruments affected by market risk include deposits, trade receivables, trade payables and accrued liabilities. The sensitivity analyses in the following sections relate to the position as at 30 June 2018 and 30 June 2017. The sensitivity analyses have been prepared on the basis that the amount of the financial instruments in foreign currencies is all constant. 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. The analyses exclude the impact of movements in market variables on the carrying value of provisions. The following assumptions have been made in calculating the sensitivity analyses: • The statement of financial position sensitivity relates to US-denominated trade receivables • The sensitivity of the relevant profit before tax item and/or equity is the effect of the assumed changes in respective market risks. This is based on the financial assets and financial liabilities held at 30 June 2018 and 30 June 2017 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 the Group’s functional currency of Australian dollars. The majority of costs related to the Sole Gas Project 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. 108 Notes to the Financial StatementsFor the year ended 30 June 201820. Financial risk management objectives and policies continued Currently the Group has no foreign exchange hedge programmes in place. The Chief Financial Officer 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 (current and non-current) Cash held in escrow Consolidated 2018 $’000 5,403 7,852 20,171 2017 $’000 2,680 4,011 - The following table summarises the sensitivity of financial instruments held at the year end, to movements in the exchange rates for the Australian dollar to the foreign currency, with all other variables held constant. If the Australian dollar were higher at the balance date by 10% If the Australian dollar were lower at the balance date by 10% b) Commodity price risk Impact on after tax profit 2018 $’000 (1,205) 1,473 2017 $’000 (608) 743 The Group uses oil price options to manage some of its transaction exposures. Options entered into in the 2018 financial year 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. Certain options entered into prior to the 2018 financial year were designated as cash flow hedges. The following table shows the effect of price changes in oil on the Group’s provisional sales excluding the effect of hedging. Commodity price risk arises from the sale of oil denominated in US dollars. The Group has provisional sales at 30 June 2018 of $7,852,230 (2017: $4,011,293). If the Brent Average price were higher at the balance date by 10% If the Brent Average price were lower at the balance date by 10% c) Interest rate risk The Group has borrowings of $116,922,982 at 30 June 2018 (2017: $ nil). Interest on borrowings are capitalised. The Group has interest bearing deposits of $ nil (2017: $98,000,000). If the interest rate were 1% rate higher at the balance date If the interest rate were 1% rate lower at the balance date Credit risk Impact on after tax profit 2018 $’000 901 (901) 2017 $’000 461 (461) Impact on after tax profit 2018 $’000 - - 2017 $’000 314 (314) 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. 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. Exposure at balance date is addressed in each applicable note. The Group managed its credit risk with interest rate swaps, designated as cash flow hedges, refer to note 21. The Group trades only with recognised creditworthy third parties. The Group has had no exposure to bad debts. 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. 109 Notes to the Financial StatementsFor the year ended 30 June 201820. Financial risk management objectives and policies continued Cash and cash equivalents and term deposits are held at three financial institutions that have a Standard & Poor’s A credit rating or better. Trade receivables are settled on 30 to 90 day terms. 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 Company’s financial liabilities based on contractual undiscounted payments: At 30 June 2018 Trade and other payables Interest bearing loans and borrowings Financial liabilities Derivative financial liabilities Derivative financial liabilities designated in a hedge relationship At 30 June 2017 Trade and other payables Financial liabilities Derivative financial liabilities designated in a hedge relationship Share price risk Less than 3 months $’000 3 to 12 months $’000 1 to 5 years $’000 Greater than 5 years $’000 Total $’000 57,756 1,967 - 91 - - - - 57,756 5,902 56,747 104,141 168,757 - 145 355 5,000 - 177 - - - 5,000 236 532 59,814 6,402 61,924 104,141 232,281 58,520 - 57 58,577 - - 57 57 - 5,000 - 5,000 - - - - 58,520 5,000 114 63,634 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. If the share price were 10% higher at the balance date If the share price were 10% lower at the balance date 21. Hedge accounting Impact on revaluation reserve 2018 $’000 223 (224) 2017 $’000 66 (66) The Company 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. In the prior period the Company designated its oil price options in a hedge relationship. These options matured in December 2017 with subsequent oil price options entered into during the 2018 financial year not being designated in a hedge relationship. 110 Notes to the Financial StatementsFor the year ended 30 June 201821. Hedge accounting continued 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 Company’s reserve base lending facility. These forecast transactions are highly probable, and they comprise 95% of the Company’s total expected interest payments June 2020. Carrying amount $0.5 million (2017: Nil) Notional value Hedge cover Maturity date Average hedged rate $118.4 million (2017: Nil) 94% June 2020 6.43% The fair value of the swaps vary based on the level of sales and changes in forward rates. Fair value of oil price options Fair value of interest rate swaps 30 June 2018 30 June 2017 Assets $’000 Liabilities $’000 Assets $’000 Liabilities $’000 - - - 532 - - 114 - The terms of the interest rate swaps match the terms of the expected highly probable forecast interest payments. During the financial year, $0.3 million was reclassified from other comprehensive income (OCI) to capitalised borrowing costs on the balance sheet in respect of realised hedge settlements. The cash flow hedges of the expected future interest payments were assessed to be highly effective and a net unrealised loss of $0.5 million and a tax expense of $0.1 million relating to the hedging instrument are included in OCI. The amounts retained in OCI at 30 June 2018 are expected to mature and impact the statement of profit or loss during the 2019 and 2020 financial year. 22. Commitments and contingencies Operating lease commitments under non-cancellable office lease not provided for in the financial statements and payable: Within one year After one year but not more than five years After more than five years Total minimum lease payments The Parent entity leases an office in Adelaide and Perth from which it conducts its operations. Exploration capital commitments not provided in the financial statements and payable: Within one year (i) After one year but not more than five years After more than five years Total minimum lease payments Consolidated 2018 $’000 2017 $’000 888 2,826 1,246 4,960 5,776 20,130 - 255 - - 255 14,600 30 - 25,906 14,630 (i) The joint venture has applied for a revision to the work schedule that is currently with the minister for approval. 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 2018 the Parent entity has bank guarantees for $945,825 (2017: $160,512). These guarantees are in relation to performance bonds on exploration permits and guarantees on office leases. 111 Notes to the Financial StatementsFor the year ended 30 June 201823. Interests in joint arrangements The Group has interests in a number of joint arrangements which are classified as joint operations. These joint operations are involved in the exploration and/or production of oil in Australia. The Group has the following interests in joint arrangements in the following major areas: Joint Arrangements in which Cooper Energy Limited is not the operator/manager Australia PEL 90K PEL 93* PRL 237 PEL 100 PRL 183-190 (Formerly PEL 110) PEL 494 PEP 150 PEP 168 PEP 171 PRL 32 PRL 85-104* (Formerly PEL 92) *Includes associated PPLs Oil and gas exploration Oil and gas exploration and production Oil and gas exploration Oil and gas exploration Oil and gas exploration Oil and gas exploration Oil and gas exploration Oil and gas exploration Oil and gas exploration Oil and gas exploration Oil and gas exploration and production Ownership Interest 2018 2017 25% 30% 20% 25% 30% - 19.165% 19.165% 20% 30% 20% 50% 25% 30% 25% 20% 30% 20% 50% 25% 30% 25% It is noted that the Victorian gas assets acquired in the 2017 financial year do not meet the definition of joint arrangements and as such are not included in this note. 24. Related parties The Group has a related party relationship with its subsidiaries, its joint arrangements (see Note 23) and with its key management personnel (refer to disclosure for key management personnel below). Key management personnel disclosures The following were key management personnel of the Group at any time during the reporting period and unless otherwise indicated were key management personnel for the entire period. Non-Executive Directors Mr J. Conde AO (Chairman) Ms E. Donaghey1 Mr H. Gordon Mr J. Schneider Ms A. Williams Executives at year end Executive Directors Mr D. Maxwell Mr D. Clegg (General Manager Development) Ms A. Evans (Company Secretary and Legal Counsel) Mr E. Glavas (General Manager Commercial and Business Development) Mr M. Jacobsen (General Manager Projects) Mr I. MacDougall (General Manager Operations) Ms V. Suttell (Chief Financial Officer) Mr A. Thomas (General Manager Exploration & Subsurface) 1. Ms Donaghey was appointed a Non-executive Director of the Company effective from 25 June 2018. 112 Notes to the Financial StatementsFor the year ended 30 June 201824. Related parties continued The key management personnel’s remuneration included in General Administration (see Note 4) is as follows: Short-term benefits Other long-term benefits Post-employment benefits Performance Rights and Share Appreciation Rights Termination benefits Total Subsidiaries Consolidated 2018 $ 2017 $ 5,905,751 4,355,038 108,807 220,058 94,811 183,275 1,825,974 1,395,760 - 283,371 8,060,590 6,312,255 The Group 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 Coper Energy (Australia) Pty Ltd Cooper Energy (PBF) Pty Ltd Cooper Energy (PB Pipeline) 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 (PBGP) 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 Equity interest 2018 % 2017 % 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% -1 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% 1. Company was divested and sold to APA Group as part of the sale of the Orbost Gas Plant Joint arrangements During the reporting period, the Group provided geological and technical services to joint arrangements it manages at a cost of $nil (2017: $1,454,000). At the end of the financial period, nothing was outstanding for these services (2017: $nil). An impairment assessment is undertaken each financial year of related party receivables with reference to the lifetime expected credit loss model. Where there is evidence that a related party receivable is impaired the Group recognises an allowance for the impairment loss. 113 Notes to the Financial StatementsFor the year ended 30 June 201825. Share based payment plans There are two share based payment plans in place at 30 June 2018. On 12 November 2015 shareholders of Cooper Energy approved the second 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. Testing of the performance rights and share appreciation rights will occur once over the performance period and if required 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 a weighted basket of absolute total shareholder returns of 12 peer companies listed on the Australian Stock 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. Rights that do not qualify for vesting in the third year can be carried forward to the following year for retesting of vesting eligibility. There are no participating rights or entitlements inherent in the rights and holders will not be entitled to participate in new issues of capital offered to shareholders during the period of the rights. All rights are settled by physical delivery of shares. Information with respect to the number of performance rights and share appreciation rights granted to employees is as follows: Date Granted Number of share appreciation rights (SARs) granted Number of performance rights granted 15 December 2015 22,278,100 21 December 2016 8 December 2017 9,841,875 15,898,978 7,892,812 3,810,503 6,330,443 The number of performance rights held by employees is as follows: Average share price at commencement date of grant Average contractual life of rights at grant date in years Remaining life of rights in years $0.175 $0.298 $0.310 3 3 3 0.5 1.5 2.5 Balance at beginning of year - granted - vested - expired and not exercised - forfeited following employee termination Balance at end of year Achieved at end of year The number of share appreciation rights held by employees is as follows: Balance at beginning of year - granted - vested - expired and not exercised - forfeited following employee termination Balance at end of year Achieved at end of year Number of Rights 2018 2017 10,994,298 6,330,443 - - - 7,892,812 3,810,503 (233,975) - (475,042) 17,324,741 10,994,298 - - Number of Rights 2018 2017 30,118,716 22,278,100 15,898,978 - - - 9,841,875 (660,415) - (1,340,844) 46,017,694 30,118,716 - - 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. 114 Notes to the Financial StatementsFor the year ended 30 June 201825. Share based payment plans continued 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 2011 Employee Performance Rights Plan 15 December 2015 21 December 2016 6.2 cents 17.5 cents 1.95% 50% 0% 15.1 cents 29.78 cents 1.575% 56% 0% 15 December 2015 21 December 2016 13.1 cents 16.5 cents 2.13% 53% 0% 28.3 cents 34.5 cents 1.88% 56% 0% 8 December 2017 12.4 cents 29.5 cents 1.94% 56% 0% 8 December 2017 22.4 cents 29.5 cents 1.94% 56% 0% On 16 December 2011 shareholders of Cooper Energy approved the establishment of an Employee Performance Rights Plan (2011 Plan) whereby the Board can, subject to certain conditions, issue performance rights to employees to acquire shares in the parent entity. No issues of performance rights under the 2011 Plan were made during the financial year. Testing of the performance rights will be in three equal tranches over the term of the right to be determined in the fourth calendar quartile of each year. At the end of the three year measurement period, those rights that were tested and achieved will vest. The vesting test is two parts. Up to 25% of the eligible rights to be tested are determined from the absolute total shareholder return of Cooper Energy’s share price against its own share price at the date of the grant of the right. If the return is less than 5% no rights will vest. If the return is between 5% and 25% the rights that will vest will be between 6.25% and 12.5% of the eligible rights. If the return is greater than 25% up to 25% of the eligible rights will vest. The second part is for the remaining 75% of the eligible rights to vest and is determined from the absolute total shareholder return of Cooper Energy’s share price ranked against a weighted basket of absolute total shareholder returns of peer companies listed on the Australian Stock Exchange. If Cooper Energy’s ranking is lower than 6 out of 9 of peer companies no rights will vest. If the ranking is 5th 50% of the eligible rights will vest. If Cooper Energy is ranked 3rd or 4th, prorate 50% to 100% of the eligible rights will vest and if it ranks 1st or 2nd, 100% of the eligible rights will vest. Rights that do not qualify for vesting in any one year can be carried forward to the following year for testing of vesting eligibility. 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. The number of performance rights held by employees is as follows: Balance at beginning of year - granted - vested - expired and not exercised - forfeited following employee termination Balance at end of year Achieved at end of year Number of rights 2018 Number of rights 2017 5,300,196 11,167,070 - - (3,975,157) (4,535,319) (1,325,039) - - - (886,918) (444,637) 5,300,196 2,650,106 The weighted average price of shares vested during the financial year was $0.30 per share. 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. 115 Notes to the Financial StatementsFor the year ended 30 June 201826. Auditors remuneration The auditor of Cooper Energy Limited is Ernst & Young Amounts received or due and receivable by Ernst & Young Australia for: Auditing and review of financial reports of the entity and the consolidated Group Taxation and other services Services in relation to one off transactions 27. Parent entity information Information relating to Cooper Energy Limited Current Assets Total Assets Current Liabilities Total Liabilities Issued capital Accumulated loss Option premium reserve Cash flow hedge reserve Equity instruments reserve Share based payment reserve Total shareholders’ equity Profit/(Loss) of the parent entity Consolidated 2018 $ 2017 $ 330,000 79,702 92,485 217,259 65,000 - 502,187 282,259 2018 $’000 2017 $’000 416,213 700,530 145,306 227,749 471,837 155,552 436,960 61,308 111,539 343,161 (30,524) (33,980) 25 310 (869) 9,586 450,365 22,416 25 161 (685) 7,818 316,500 (13,415) Total comprehensive income/(loss) of the parent entity (35) 729 Commitments and Contingencies Operating lease commitments under non-cancellable office lease not provided for in the financial statements and payable: Within one year After one year but not more than five years After more than five years Total minimum lease payments 28. Events after the reporting period Sole-3 flow-back 888 2,826 1,246 4,960 255 - - 255 On 6 July 2018, the Company announced that Sole-3 is being shut-in for future connection after successful performance of clean-up and flow back operations. Debt drawdown On 23 July 2018, the Company utilised a further $25.7 million of its Reserve Base Loan Facility. Sole-4 flow-back On 6 August 2018, the Company announced that Sole-4 is being shut-in for future connection after successful performance of clean-up and flow back operations. 116 Notes to the Financial StatementsFor the year ended 30 June 2018Directors’ Declaration In accordance with a resolution of the Directors of Cooper Energy Limited, I state that: In the opinion of the Directors: (a) the financial statements and notes of the consolidated entity are in accordance with the Corporations Act 2001, including: (i) giving a true and fair view of the consolidated entity’s financial position as at 30 June 2018 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 Note 2b; (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; and (d) 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 2018. Signed in accordance with a resolution of the Directors. Mr John C. Conde AO Chairman 13 August 2018 Mr David P. Maxwell Managing Director 117 Ernst & Young 121 King William Street Adelaide SA 5000 Australia GPO Box 1271 Adelaide SA 5001 Tel: +61 8 8417 1600 Fax: +61 8 8417 1775 ey.com/au Independent Auditor’s Report to the Members of Cooper Energy Limited Report on the Audit of the Financial Report Opinion We have audited the financial report of Cooper Energy Limited (the Company) and its subsidiaries (collectively the Group), which comprises the consolidated statement of financial position as at 30 June 2018, consolidated statement of comprehensive income, consolidated statement of changes in equity and consolidated statement of cash flows for the year then ended, notes to the financial statements, including a summary of significant accounting policies, and the directors declaration. In our opinion, the accompanying financial report of the Group is in accordance with the Corporations Act 2001, including: a) b) giving a true and fair view of the consolidated financial position of the Group as at 30 June 2018 and of its consolidated financial performance for the year ended on that date; and complying with Australian Accounting Standards and the Corporations Regulations 2001. Basis for Opinion We conducted our audit in accordance with Australian Auditing Standards. Our responsibilities under those standards are further described in the Auditor’s Responsibilities for the Audit of the Financial Report section of our report. We are independent of the Group in accordance with the auditor independence requirements of the Corporations Act 2001 and the ethical requirements of the Accounting Professional and Ethical Standards Board’s APES 110 Code of Ethics for Professional Accountants (the Code) that are relevant to our audit of the financial report in Australia. We have also fulfilled our other ethical responsibilities in accordance with the Code. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion. Key Audit Matters Key audit matters are those matters that, in our professional judgement, were of most significance in our audit of the financial report of the current year. These matters were addressed in the context of our audit of the financial report as a whole, and in forming our opinion thereon, but we do not provide a separate opinion on these matters. For each matter below, our description of how our audit addressed the matter is provided in that context. We have fulfilled the responsibilities described in the Auditor’s Responsibilities for the Audit of the Financial Report section of our report, including in relation to these matters. Accordingly, our audit included the performance of procedures designed to respond to our assessment of the risks of material misstatement of the financial report. The results of our audit procedures, including the procedures performed to address the matters below, provide the basis for our audit opinion on the accompanying financial report. A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 118 1. Estimation of oil and gas reserves and resources Why significant How our audit addressed the key audit matter Estimation of oil and gas reserves and resources requires significant judgement and the use of assumptions by the Group, as outlined in note 2 bb) (ii) of the Group’s financial report. These estimates can have a material impact on the financial statements, primarily in the following areas: capitalisation and classification of expenditure as exploration and evaluation (E&E) assets (Refer note 15) or oil and gas assets (note 12); valuation of assets and impairment testing (note 13); calculation of depreciation, depletion and amortisation (DD&A) (note 4); and • • • • estimation of the timing of decommissioning and restoration activities (note 17). • Our audit procedures focused on the work of the Group’s experts with respect to the hydrocarbon reserve estimations. Our procedures included the following: • • • assessed the qualifications, competence and objectivity of the Groups’ internal experts involved in the estimation process. assessed controls over the estimation process employed by the Group. assessed whether key economic assumptions used in the estimation of reserves and resources volumes were consistent with those utilised by the Group in the impairment testing of exploration and evaluation and oil and gas assets, where applicable. analysed the reasons for reserve revisions, or the absence of reserves revisions where expected, and assessed movements in reserves for consistency with other information that we obtained throughout the audit. • ensured the reserves volumes used in the determination of information recorded in the financial statements, such as the calculation of DD&A, valuation of assets and impairment testing, and the calculation of decommissioning provisions, were consistent with those addressed through these procedures. A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 119 2. Impairment assessment of oil and gas assets Why significant How our audit addressed the key audit matter Australian Accounting Standards require the Group to assess throughout the reporting period whether there is any indication that an asset may be impaired, or that reversal of a previously recognised impairment may be required. If any such indications exist, the Group shall estimate the recoverable amount of the asset. An asset is also required to be tested for impairment immediately before an exploration and evaluation asset is transferred to assets in development. As outlined in note 2 a) the Final Investment Decision (FID) for the Sole Gas Project was made on 29 August 2017. This triggered the transfer of the project from exploration and evaluation to Oil and Gas Assets - Asset in Development. An impairment assessment was performed immediately prior to the transfer to Assets in Development. The Group’s testing determined that no impairment was required on transfer to Assets in Development. Impairment indicators were also present during the period for certain cash generating units (CGUs), and impairment testing was undertaken where required. The Group’s testing determined that no impairment of oil and gas assets was required. The impairment testing process is complex and highly judgemental and is based on assumptions and estimates that are affected by expected future performance and market conditions. Key assumptions, judgements and estimates used in the formulation of the Group’s impairment of and oil and gas assets are set out in the financial report in note 2 bb). We evaluated the assumptions and methodologies used by the Group and the estimates made. In particular we considered those estimates and judgements relating to the forecast cash flows and the inputs used to formulate those cash flows, such as discount rates, reserves and resources, operating and capital costs, commodity prices and foreign exchange rates. We involved our valuation specialists to assist in these procedures. Our audit procedures were undertaken across all significant CGUs, with the extent of procedures commensurate with the level of impairment risk. Specifically, we evaluated the discounted cash flow models and other data supporting the Group’s assessment for those CGUs where impairment indicators were present. In doing so, we: • • • understood future production profiles compared to latest reserves and resources estimates, as outlined in the key audit matter above, current approved budgets and forecasts and historical operations, where relevant; evaluated commodity price assumptions with reference to contractual arrangements, market prices (where available), broker consensus, analyst views, market regulators and historical performance; evaluated discount rates and foreign exchange rates with reference to risk free rates, market indices, market risk, company and project risk, applicable tax rates, market expectations, and historical performance; compared future operating and capital expenditure to current approved budgets, forecasts, contractual arrangements and historical expenditure, and ensured variations were in accordance with our expectations based upon other information obtained throughout the audit; tested the mathematical accuracy of the Group’s discounted cash flow models. • • We also considered the adequacy of the financial report disclosures regarding key judgement and assumptions with respect to the impairment assessment. A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 120 3. Decommissioning and restoration provisions Why significant How our audit addressed the key audit matter The Group has recognised decommissioning and restoration provisions of $173.7 million at 30 June 2018 which are disclosed in note 17 of the Group’s financial report. This includes the assumption of additional decommissioning and restoration liabilities from exited parties as set out in note 2 a) and note 17. The calculation of decommissioning and restoration provisions requires judgement in respect of asset lives, timing of restoration work being undertaken, environmental legislative requirements, the extent of restoration activities required and future restoration costs. Our audit procedures focused on the work of the Group’s experts. Our audit procedures included the following: • • assessed the qualifications, competence and objectivity of both the Group’s internal and external experts involved in the estimation process. evaluated the adequacy of the expert’s work to determine whether their work was appropriate, including understanding the basis for forecast cost assumptions for decommissioning and restoration. • assessed the effectiveness of relevant controls over the Group’s decommissioning and restoration provision estimation process. • ensured the consistency in the application of principles and assumptions to other financial statement areas such as reserves estimation and impairment testing. • • tested the mathematical accuracy of the net present value calculations. assessed the Group’s disclosures in respect of the decommissioning and restoration provisions. A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 121 4. Accounting for deferred tax and Petroleum Resource Rent Tax Why significant How our audit addressed the key audit matter We assessed the Group’s determination of tax payable now and deferred tax. We involved our taxation specialists to assist in this assessment. We assessed the application of the methodologies used, and the judgements involved in estimating the utilisation of deferred tax benefits in the future, and in assessing the offsetting of corporate income tax deferred tax assets and liabilities. We assessed the estimation of future taxable income, the interpretation of PRRT and income tax legislation and the consistency in the application of forecast performance with other forecasts made, such as in the Group’s impairment testing and corporate modelling. We assessed the Group’s disclosures in respect of PRRT and income taxes which are included in the summary of significant accounting policies in note 5 to the financial report. The Group has recognised a net deferred tax asset of $10.3 million at 30 June 2018 in respect of corporate income tax which is disclosed in note 5 to the financial report. In arriving at the net deferred tax asset, consideration has been given to temporary differences arising on assets and liabilities, and carry forward losses in respect of corporate income tax, which are available for offset against amounts payable in future periods. The Group has interests in a number of assets subject to the Australian Petroleum Resource Rent Tax (“PRRT”) regime. The Group has recognised a net deferred tax liability of $10.4 million at 30 June 2018 as disclosed in note 5. Deferred tax assets in respect of the PRRT regime, arising due to carried forward undeducted expenditure, have not been recognised in relation to a number of assets. Further details are set out in note 5 to the financial report. The determination of the quantum, likelihood and timing of the realisation of deferred tax assets arising from corporate income taxes and PRRT is complex and judgemental. The Group’s accounting policies and disclosures regarding PRRT and income taxes are included in the summary of significant accounting policies in note 2 bb) and in note 5 to the financial report. A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 122 Information Other than the Financial Report and Auditor’s Report The directors are responsible for the other information. The other information comprises the information included in the Company’s 30 June 2018 Annual Report, but does not include the financial report and our auditor’s report thereon. We obtained the Directors’ Report and the Overall Financial Review that are to be included in the Annual Report, prior to the date of this auditor’s report, and we expect to obtain the remaining sections of the Annual Report after the date of this auditor’s report. Our opinion on the financial report does not cover the other information and we do not and will not express any form of assurance conclusion thereon, with the exception of the Remuneration Report and our related assurance opinion. In connection with our audit of the financial report, our responsibility is to read the other information and, in doing so, consider whether the other information is materially inconsistent with the financial report or our knowledge obtained in the audit or otherwise appears to be materially misstated. If, based on the work we have performed on the other information obtained prior to the date of this auditor’s report, we conclude that there is a material misstatement of this other information, we are required to report that fact. We have nothing to report in this regard. Directors’ Responsibilities for the Financial Report The Directors of the Company are responsible for the preparation of the financial report that gives a true and fair view in accordance with Australian Accounting Standards and the Corporations Act 2001 and for such internal control as the Directors determine is necessary to enable the preparation of the financial report that gives a true and fair view and is free from material misstatement, whether due to fraud or error. In preparing the financial report, the Directors are responsible for assessing the Group’s ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless the directors either intend to liquidate the Group or cease operations, or have no realistic alternative but to do so. Auditor’s Responsibilities for the Audit of the Financial Report Our objectives are to obtain reasonable assurance about whether the financial report as a whole is free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with Australian Auditing Standards will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of this financial report. A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 123 As part of an audit in accordance with Australian Auditing Standards, we exercise professional judgement and maintain professional scepticism throughout the audit. We also: • Identify and assess the risks of material misstatement of the financial report, whether due to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. • Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Group’s internal control. • Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by the directors. • Conclude on the appropriateness of the directors’ use of the going concern basis of accounting and, based on the audit evidence obtained, whether a material uncertainty exists related to events or conditions that may cast significant doubt on the Group’s ability to continue as a going concern. If we conclude that a material uncertainty exists, we are required to draw attention in our auditor’s report to the related disclosures in the financial report or, if such disclosures are inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up to the date of our auditor’s report. However, future events or conditions may cause the Group to cease to continue as a going concern. • Evaluate the overall presentation, structure and content of the financial report, including the disclosures, and whether the consolidated financial statements represent the underlying transactions and events in a manner that achieves fair presentation. • Obtain sufficient appropriate audit evidence regarding the financial information of the entities or business activities within the Group to express an opinion on the financial report. We are responsible for the direction, supervision and performance of the Group audit. We remain solely responsible for our audit opinion. We communicate with the Directors regarding, among other matters, the planned scope and timing of the audit and significant audit findings, including any significant deficiencies in internal control that we identify during our audit. We also provide the Directors with a statement that we have complied with relevant ethical requirements regarding independence, and to communicate with them all relationships and other matters that may reasonably be thought to bear on our independence, and where applicable, related safeguards. From the matters communicated to the Directors, we determine those matters that were of most significance in the audit of the financial report of the current year and are therefore the key audit matters. We describe these matters in our auditor’s report unless law or regulation precludes public disclosure about the matter or when, in extremely rare circumstances, we determine that a matter should not be communicated in our report because the adverse consequences of doing so would reasonably be expected to outweigh the public interest benefits of such communication. A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 124 Report on the Remuneration Report Opinion on the Remuneration Report We have audited the Remuneration Report included in pages 56 to 70 of the Directors’ Report for the year ended 30 June 2018. In our opinion, the Remuneration Report of Cooper Energy Limited for the year ended 30 June 2018, complies with section 300A of the Corporations Act 2001. Responsibilities The Directors of the Company are responsible for the preparation and presentation of the Remuneration Report in accordance with section 300A of the Corporations Act 2001. Our responsibility is to express an opinion on the Remuneration Report, based on our audit conducted in accordance with Australian Auditing Standards. Ernst & Young L A Carr Partner Adelaide 13 August 2018 A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 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 Cooper Energy Limited for the financial year ended 30 June 2018, 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 13 August 2018 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 2018 Listing The company’s shares are quoted on the Australian Securities Exchange under the code of “COE”. Number of Shareholders There were 7,114 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 2018) Size of Shareholding 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 28 14 Number of holders Number of Shares % of issued capital 927 1,665 1,067 2,798 657 7,114 235,085 4,914,078 8,655,414 102,535,844 1,484,738,336 1,601,078,757 0.01 0.31 0.54 6.40 92.73 100.00 Total Performance Rights 17,846,179 Performance Rights 46,017,694 Share Appreciation Rights Unmarketable Parcels There were 974 members, representing 285,312 shares, holding less than a marketable parcel of 1,124 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. HSBC Custody Nominees (Australia) Limited JP Morgan Nominees Australia Limited Citicorp Nominees Pty Limited BNP Paribas Nominees Pty Ltd National Nominees Limited UBS Nominees Pty Ltd BNP Paribas Noms Pty Ltd Zero Nominees Pty Ltd UBS Nominees Pty Ltd Kavel Pty Ltd HSBC Custody Nominees (Australia) Limited-GSCO ECA Mirrabooka Investments Limited Citicorp Nominees Pty Limited Invia Custodian Pty Ltd Nero Resource Fund Pty Ltd Mr Leendert Hoeksema + Mrs Aaltje Hoeksema Mr Timothy Bryce Kleemann Levak Nominees Pty Ltd Rocket Science Pty Ltd Nero Resource Fund Pty Ltd Units % of Issued Capital 334,333,669 333,207,047 209,257,455 77,560,512 68,481,993 50,727,796 30,937,813 29,415,437 18,672,580 10,292,249 10,066,258 10,000,000 9,535,695 8,042,593 6,200,000 6,000,000 5,647,682 4,919,015 4,864,934 4,636,093 20.88 20.81 13.07 4.84 4.28 3.17 1.93 1.84 1.17 0.64 0.63 0.62 0.60 0.50 0.39 0.37 0.35 0.31 0.30 0.29 Totals: Top 20 holders of Ordinary Fully Paid Shares (Total) 1,232,798,821 77.00 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 JCP Investment Partners Ltd CBA FIL AustralianSuper Pty Ltd 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 142,008,750 103,752,292 102,621,837 99,461,842 88,849,874 8.87% 6.48% 6.41% 6.21% 6.02% 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. 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. 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 128 Corporate Directory Directors John C Conde AO, Chairman David P Maxwell Elizabeth A Donaghey Hector M Gordon Jeffrey W Schneider Alice J M Williams Company Secretary Alison M Evans 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 6, 160 St Georges Terrace Perth, Western Australia 6000 Telephone: +61 8 6556 2101 Facsimile: +61 8 6556 2144 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 Hong Kong Branch Level 72, International Commerce Centre 1 Austin Road West, Kowloon, Hong Kong ABN AMRO Bank N.V., Singapore Branch Level 26 One Raffles Quay South Tower Singapore 048583 ING Bank N.V. 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 2 0 1 8 A n n u a l R e p o r t 

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