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Annual Report 2014

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ANNUAL REPORT 2014 C O O P E R E N E R G Y A N N U A L R E P O R T 2 0 1 4 Cooper Energy Limited ABN 93 096 170 295 Reporting Period, Terms and Abbreviations Annual Report This document has been prepared to provide shareholders with an overview of Cooper Energy Limited’s performance for the 2014 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 on page 99). 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 2014 Annual General Meeting of Cooper Energy Limited will be held on Wednesday 5 November, commencing at 10.30 am in the Victoria Room, Ground Floor, Adelaide Hilton, Victoria Square, Adelaide, South Australia. A formal Notice of Meeting has been mailed to shareholders. Additional copies can be obtained from the company’s registered office or downloaded from its website at www.cooperenergy.com.au Abbreviations and terms This Report uses terms and abbreviations relevant to the company, its 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 “2014”, “FY14” or “2014 financial year” refer to the 12 months ended 30 June 2014 unless otherwise stated. References to “2013”, “FY13” or other years refer to the 12 months ended 30 June of that year. “Current year” refers to the 12 months ending 30 June 2015. Other abbreviations bbls: barrels of oil EBITDA: earnings before interest, tax and depreciation kbbls: thousand barrels of oil boe: barrels of oil equivalent bopd: barrels of oil per day MMbbl: million barrels of oil MMboe: million barrels of oil equivalent LTI: lost time injury LTIFR: lost time injury frequency rate: lost time injuries per million hours worked PEL 92: the South Australian Cooper Basin acreage operated by the PEL 92 Joint Venture that previously fell within the PEL 92 licence and now falls within the retention leases PRL’s 85 – 104 and the production licences PPL’s 204, 205, 207, 220, 224, 245 – 250. 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. Front cover image: Bungaloo-1 well location, Otway Basin Image opposite: From left: Zacc Paparella, Geologist; Justin Miller, Lead Business Analyst; Joanne Bay, Project Engineer; Pedro Nemalceff, General Manager, Indonesia; Joanna Trepa, Joint Venture Accountant Cooper Energy finds, develops and commercialises oil and gas. We do this with care and strive to provide attractive returns for our shareholders and good commercial outcomes for our customers. 1 Cooper Energy is an Australian oil and gas exploration and production company with: • high margin, cash generating oil production from the Cooper Basin and Indonesia • acreage and resources for the supply of gas to eastern Australia • a management and board team with proven success in exploration, gas commercialisation and building resource companies. Key figures1: Financial $ million 12 months ended 30 June 2014 Annual revenue Net profit after tax Operating cash flow Net (Debt)/Cash & Investments Operations (million barrels) Reserves (Proved & Probable) 2C Contingent Resources (MMboe) Annual production Share information 72.3 22.0 50.3 75.1 2.01 35.1 0.59 Shares on issue (million) Market capitalisation ($ million) 329.2 166.3 1 As at 30 June 2014 2 Cooper Basin Tunis Office Gulf of Hammamet T U NI S IA I N DO N E S IA South Sumatra Jakarta Office Cooper Basin Otway Basin A U S T R A L IA Adelaide Office Gippsland Basin 3 2014 YEAR IN BRIEF In 2014 Cooper Energy: • recorded its highest profit, sales and production to date; • maintained Proved and Probable Reserves of 2 million barrels of oil and increased its 2C Contingent Resources from 6 MMboe to 35 MMboe; and • completed the year with gas resources and exploration acreage that can be the cornerstones of a multi-basin gas supply portfolio to eastern Australia. Net profit after tax EBITDA FY08 FY09 FY10 FY11 FY12 FY13 $ million 22 FY14 22.0 $ million 40 FY08 FY09 FY10 FY11 FY12 FY13 FY14 20 18 16 14 12 10 8 6 4 2 0 -2 -4 -6 -8 -10 8.4 1.2 1.3 6.4 -2.8 -10.3 36.9 22.3 15.8 8.0 5.2 9.1 -6.0 35 30 25 20 15 10 5 0 -5 -10 Production Proved and Probable Reserves MMbbl FY08 FY09 FY10 FY11 FY12 FY13 FY14 MMbbl FY08 FY09 FY10 FY11 FY12 FY13 FY14 0.6 0.5 0.4 0.3 0.2 0.1 0 4 0.59 0.52 0.49 0.49 0.47 0.41 0.38 2.47 2.00 1.91 1.88 2.16 2.01 1.44 2.5 2.0 1.5 1.0 0.5 0 Health, Safety, Environment and Community • Lost Time Injury Frequency Rate reduced from 1.75 to 0.80 • 1 Lost Time Injury for year Financial results • Sales revenue increased 35% to $72.3 million • Net profit after tax of $22.0 million up from $1.3 million • Underlying net profit after tax increased 99% to $25.3 million • Cash and financial assets at 30 June of $75.1 million up 10% Exploration and production • Total production of 0.59 million barrels of oil, up 20% from 0.49 million barrels • Proved and Probable Reserves of 2.01 million barrels of oil down from 2.16 million barrels • Contingent Resources (2C) of 35.1 million boe, up from 5.7 million boe • Oil pool discovery in Patchawarra Formation in Worrior Field • Encouraging results from Penola Trough deep drilling program in the Otway Basin Portfolio management and corporate development • Acquisition of 65% interest and operatorship of Basker Manta Gummy gas and liquids project • Expanded acreage position in Otway Basin • Divestment of Tunisian portfolio commenced 5 CHAIRMAN’S REPORT JOHN CONDE AO These results reflect the strength of the company’s existing oil producing assets, particularly those in the Cooper Basin. They are also, to a significant degree, attributable to the strategy the company has followed for the past two years. Your company is now more geographically focussed with a promising portfolio of interests including production and exploration in the sought-after Cooper Basin, prospective acreage in the Otway and Gippsland Basins and an increasingly valuable position onshore South Sumatra, Indonesia. Your board considers that this portfolio has the potential, with a combination of exploration success and supplementary acquisitions, to develop a significant new income stream from the production and sale of gas to eastern Australia in the coming years whilst also maintaining the profitable oil production that has been the base of the business. I have three observations on the results and year-end position which I consider noteworthy from a shareholder perspective. First, the significant rebuilding of the company’s portfolio, and the opportunities before it, has been achieved without depleting cash reserves and without recourse to equity raising or borrowing. Your company takes a prudent and protective approach to shareholder capital. Second, the benefits of the strategy implemented from 2012 are now clearly emerging. More material shareholder value benefits are expected as the key milestones from our exploration, development and gas commercialisation activities are achieved. Third, the record-breaking performance in 2014 was driven by the production performance of the company’s traditional Cooper Basin acreage, which grew by 17% year-on-year, supported by higher production from Indonesia. Natural decline of producing reservoirs is expected to result in lower production in 2015 from the existing fields. However, exploration and analysis of the company’s assets offers opportunities for additions to reserves with a low threshold for economic development. The company is continuing to invest in its Cooper Basin acreage as a key source of reserve addition and oil production for the foreseeable future. Statutory net profit after tax for the year of $22.0 million compares with the previous corresponding result of $1.3 million. However, as the 2013 result was adversely affected by some significant non-operating items that totalled $(11.4) million, comparison of underlying profit after tax offers a more meaningful comparison of year-on-year performance. Underlying profit after tax for 2014 was $25.3 million, a 99% increase on the previous year’s corresponding result of $12.7 million. The substantial improvement in return on shareholder funds, which rose to 14.4%, was particularly pleasing given your company’s focus on capital efficiency. It is an initial step towards the sustained performance in return and shareholder value creation that is being sought. I noted the growth in cash and financial resources in my opening comments. Total cash and financial assets available for sale at 30 June were $75.1 million compared with $68.1 million at the beginning of the year. This is a relatively large cash and liquid asset position for a company of Cooper Energy’s size. Your company has a clear strategy for the management of its capital to provide the optimal long term shareholder returns and balance sheet strength. As the Managing Director notes in his report following, Cooper Energy has funded its 2014 exploration program from the cash flow generated from operations. To a large degree, this is expected to continue and the company plans to leverage its technical capabilities and relatively high licence equities to minimise risk capital committed to the higher risk – higher reward exploration drilling in locations such as Indonesia and the Gippsland Basin. Your board is of the view that the best opportunity for sustainable growth in shareholder returns lies in the application of the company’s strong balance sheet to acquisitions and growth projects targeting a ‘step-up’ in long term production and revenue and the establishment of a portfolio based gas business. Your board has a clear strategy and criteria for the assessment of the shareholder value benefits of investment opportunities, a number of which are expected to emerge in the coming 24 months. 2014 was a landmark year for your company and so it is with pleasure that I present this report. Cooper Energy completed the 12 months to 30 June 2014 with the highest production, revenue, and profit it has recorded in its twelve year history. Reserves were broadly maintained and Contingent Resources were the highest yet achieved. The stock market capitalisation of $166 million at 30 June exceeds that of all previous year-end valuations. Cash and financial resources have also grown by 10% . Most importantly, the record financial and production results have been accompanied by a material improvement in safety and environmental performance. 6 Drilling rig, Otway Basin On behalf of shareholders, I would like to thank my fellow directors for their service on the board this year and express our appreciation for the contribution of the staff to your company’s performance. John Conde AO Chairman In April 2014 the Board of Directors inspected operations in the Cooper Basin. Pictured at Eaglehawk waterhole in the vicinity of the Sellicks and Christies oil fields are from left: Iain MacDougall, Operations Manager; Andrew Thomas, Exploration Manager; Jason de Ross, Chief Financial Officer; Hector Gordon, Executive Director – Exploration and Production; John Conde, Chairman; David Maxwell, Managing Director; Alice Williams, Non-Executive Director; Alison Evans, Company Secretary and Jeff Schneider, Non-Executive Director. 7 MANAGING DIRECTOR’S REPORT DAVID MAXWELL In respect of gas, Cooper Energy is now the major interest holder and Operator in the Basker Manta Gummy (BMG) fields offshore Gippsland Basin which are assessed to contain 2C Contingent Resources of 119 PJ (100% joint venture share). The 3C Contingent Resource assessment is 209 PJ (100% joint venture share). The process of analysing and documenting a business case for the fields’ development has commenced, as has evaluation of further resource addition opportunities in the fields and surrounding region. In the Otway Basin, we expanded our acreage position and identified a promising conventional gas play to supplement the shale gas play currently under investigation. Record oil production drove record sales and earnings results. Our strong cash flow enabled the company to fund capital expenditure and still increase year-end cash. In Indonesia, annual oil production rose 120% and seismic acquisition and processing was undertaken in the Sumbagsel and Merangin III permits. These achievements, and the record financial results documented in this report are the early benefits of the decision, and subsequent actions, to concentrate resources on those areas expected to generate the best sustainable returns for our shareholders. Further work and investment is required to confirm and realise the full potential of the company’s resources, acreage and position. Our plans and intentions in this respect are addressed in this report. These significant performance improvements and a 148% increase in hours worked have been accompanied by an improvement in safety performance which saw the LTIFR reduced to less than half the 2013 rate. This is an especially pleasing result and our 2014 safety performance is discussed in more detail in the Health Safety Environment and Community report on page 14. Financial results The 2014 financial results are the best your company has recorded to date, with underlying net profit after tax of $25.3 million generated from sales revenue of $72.3 million. This compares to the 2013 underlying net profit after tax of $12.7 million from sales revenue of $53.4 million. Statutory profit after tax was $22.0 million compared with $1.3 million. The strength of the year’s financial performance was reflected in shareholder return metrics. The return on shareholders funds for the year was 14.4% and total shareholder return was 34.7%. A discussion and analysis of the financial results, including reconciliation between statutory and underlying profit, is provided in the Operating and Financial Review that commences on page 30 of this report. A 20% increase in oil production was the key driver in the strong financial results. Oil production for the year was 594,000 barrels compared with 491,000 barrels in 2013, with both Cooper Basin and Indonesian operations contributing to the growth. Whilst Cooper Basin output benefited from production deferred in the previous year (due to pipeline interruption and construction) the record production is also attributable to the sustained exploration and development work of recent years. Cooper Energy’s share of oil production from the Sukananti KSO (Indonesia) was 55,000 barrels compared with 25,000 barrels in the previous year, an improvement achieved by our success in lifting the productivity of existing wells. There is opportunity to further increase production from the Sukananti KSO and a program of well work-overs, appraisal and development drilling is being implemented in the current year for this purpose. The earnings impact of the year’s higher production growth was magnified by stronger oil prices. The company received an average oil price of A$124.08 per barrel for the year, 10% higher than the 2013 comparative of A$112.31 per barrel. Exploration A detailed report on the year’s exploration and development activities and reserves and resources position has been provided by the Executive Director, Hector Gordon commencing on page 15. I will comment on the key outcomes and points of significance. In my report to shareholders last year I noted that Cooper Energy was positioned to step up the execution of its strategy. Consistent with this, I am pleased to advise that in 2014 Cooper Energy has applied its balance sheet and technical resources to building a portfolio-based gas business to address opportunities identified in eastern Australia, maintained strong oil production, and added value to its Indonesian assets. 8 The company maintained 2P Reserves of approximately 2 million barrels notwithstanding the record production and a low level of exploration drilling compared with previous years. Contingent Resources (2C) increased more than five-fold from 5.7 MMboe to 35.1 MMboe in 2014. These Contingent Resources are expected to be a base ingredient for reserve growth and value creation in future years. I note that Cooper Energy does not include unconventional accumulations in its estimation of reserves and resources at this stage. It is important to appreciate the significance of the successes in the year’s exploration program that is not reflected in simple drilling statistics. In the Cooper Basin, successful appraisal drilling in the Worrior field discovered a new oil pool in the Patchawarra Formation which has added reserves and identified a new play for appraisal drilling which will be addressed in 2015. In the Otway Basin, the deep well exploration program in the Penola Trough exceeded expectations. This program was conducted primarily to gather core and other information on the shale gas potential of the Casterton Formation. The two wells drilled (Jolly-1 and Bungaloo-1) reinforced the potential within the acreage for shale gas and also identified a deep conventional gas play. The new conventional gas play has added another dimension to the Otway Basin’s potential as a favourably located source of gas, at a time when gas supply is tight and gas prices are increasing in eastern Australia. The 2014 exploration program continued the increased investment in seismic acquisition, processing and interpretation commenced in the previous year. Cooper Energy has invested over $8 million in seismic over the past two years, and the flow-on from this effort is evident in our plans for the company’s largest drilling program yet in 2015. The seismic program has significantly extended the three dimensional (3D) coverage of our Cooper Basin acreage and, as a consequence, we are now planning to drill the first wells located with the benefit of ‘3D’ in PELs 100 and 110 during 2015. Our 3D coverage of the PEL 92 acreage has been extended and wells using this information are planned for the second half of 2015. The company’s understanding of its Gippsland Basin acreage and surrounds and the Sumbagsel and Merangin III permits in South Sumatra are also being upgraded through the interpretation of acquired or reprocessed seismic. Basker Manta Gummy project The company acquired a 65% interest, and the role of operator, in the BMG gas and liquids resource in the Gippsland Basin located offshore Australia during the year. The Gippsland Basin has been identified by Cooper Energy as a likely competitive source of gas for eastern Australia. The region has historically been the largest source of supply for eastern Australia and holds undeveloped gas resources and prospective acreage. These resources and prospects are conventional in nature and well located with respect to existing gas infrastructure. The BMG project was previously a producing oil project and is estimated to contain Contingent Resources (2C) of 28 million boe (100% joint venture; Cooper Energy share: 18 million boe) of gas and liquids which, it is considered, can be produced economically given suitable gas supply contracts and successful appraisal drilling. The economic feasibility of development is assisted by the wells and sub-sea infrastructure in place from the previous operations. In addition, the proximity of other adjacent gas resources raises the prospect of further economic enhancement through coordination of contracting and development. Cooper Energy acquired the interest in BMG for consideration of $1 million with a further $5 million payable on first commercial production of hydrocarbons. Work on the analysis and documentation of a business case and requirements for the fields’ commercialisation and development has already commenced with a view to completing the analysis of exploration opportunities, facilities and economics within the June quarter 2015. Portfolio Management of the company’s portfolio is ongoing to ensure Cooper Energy has exposure, and is directing its resources to, those opportunities expected to provide the best risk-weighted return for shareholders. The processes involved in acquiring, bidding for, or divesting licences and interests mean that this is, by nature a long term, and disciplined, exercise that needs to be performed in an orderly manner to deliver the objective of maximising shareholder value. Cooper Energy has been progressively redirecting expenditure away from a diverse international scope to a greater Australian focus. In particular, the company has been increasing expenditure and exposure to those assets around which it can build a sustainable value-generating gas business and maintain a valuable and growing oil business. Consistent with this, the company increased its exposure to the Penola Trough of the Otway Basin during 2014 through an equity swap with fellow Otway Basin explorer Beach Energy Limited. The transaction, at zero net cost to Cooper Energy, has provided the company with a 30% equity across the key tenements in the South Australian section of the Penola Trough. The company also secured interests in the Victorian tenement PEP 171, which covers the eastern portion of the Penola Trough and the adjoining Otway Basin permit PEP 150. Cooper Energy now ranks among the largest interest holders in the Otway Basin with a total holding of 10,191 square kilometres. The company increased its shareholding in Bass Strait Oil Company Limited (BAS) to 22.9% during the year. BAS’ interests include equity positions in exploration permits immediately adjacent to the BMG project. The divestment of the Tunisian portfolio was initiated during the year and the process is ongoing. We expect to make an announcement on the divestment within 2014. Cooper Energy continues to screen and assess acreage and asset acquisition opportunities that are consistent with strategy and offer the appropriate total shareholder return. Disciplined analysis and application of screening criteria means that only a very small fraction of the opportunities assessed during the year were either acted upon or remain under consideration. Notwithstanding this, corporate development is in line with our plans and capital is available for opportunities consistent with strategy that offer value for shareholders. 9 MANAGING DIRECTOR’S REPORT DAVID MAXWELL Balance sheet and finance 2015 outlook This disciplined approach combined with the cash flow generated by producing assets enabled balance sheet strength to increase notwithstanding the company’s largest capital expenditure program to date. Cash and financial assets available for sale at 30 June was $75.1 million compared with $68.1 million 12 months earlier. These resources are supported by undrawn finance facilities. Human Resources Cooper Energy’s workforce is developing consistent with its strategy and asset base. At 30 June 2014 Cooper Energy employed 24 full time equivalent employees in Australia and a further 47 persons in its operated assets in Indonesia and Tunisia. The company has increased its technical and commercial resources to address the expansion in its opportunities in the Otway Basin and Gippsland Basin and other potential new interests and activities. This includes the appointment of senior management to oversee the growing operational and commercial requirements and opportunities. Our senior management team is profiled on page 28. In 2015 Cooper Energy will: • test and mature some of the new opportunities identified through drilling, such as in the northern Cooper Basin and Indonesia; • manage analysis and the identification of the best business case for development of BMG; • conduct rigorous technical analysis of the recent Penola Trough exploration results and plan the further exploration of its Otway Basin gas plays; and • pursue opportunities to replenish oil reserves from producing areas in the Cooper Basin and Indonesia with new insight and targets provided by three-dimensional seismic. An 18 well drilling program has been planned for the twelve months to June 2015. This will be the largest annual drilling program yet undertaken by Cooper Energy and, for the first time, the majority of the wells will be drilled outside the Cooper Basin PEL 92 licence area (now PRL’s 85 – 104) that historically has accounted for over 90% of our production. The Patchawarra Formation in the Worrior Field, the lightly explored Cooper Basin permits PEL’s 100 and 110 and Indonesia will all be addressed. Production is expected to fall within the range of 500,000 to 560,000 barrels of oil, exclusive of exploration success and significant interruptions to production. This range exceeds all previous years’ production with the exception of 2014. Cooper Energy possesses the balance sheet and technical and commercial expertise to capitalise on the opportunities we expect will emerge, particularly in the eastern Australian energy market. We are actively engaged in assessing opportunities, both within and outside our current asset base, with a particular focus on synergistic business development and acquisitions that add further shareholder value. As we enter what will be another busy year I acknowledge the contribution of our staff and contractors towards what has been a milestone year for the company and wish them well for what shapes as an exciting period in Cooper Energy’s development. David Maxwell Managing Director David Anthony, Staff Geologist; Diann Lozoraitis, Accounts & Payroll Officer; Daniel Panella, Financial Accountant; Riki Potts, Joint Venture Coordinator; Tim Cotton, Senior Geologist 10 STRATEGY In 2012 Cooper Energy committed to a new strategy predicated on concentrating its financial, technical and commercial resources on the activities most aligned with its expertise that would generate the best total shareholder return when conducted with due care for the environment, community and its employees. This strategy, now focussed on Australia and Indonesia, is delivering improved financial returns. Build high value oil business Develop portfolio-based gas business Value driven management of international assets Assets • Cooper Basin • Otway Basin • Gippsland Basin • South Sumatra Basin • Tunisia 2014 actions and progress • Record production of 594 kbbls from • Acquired BMG gas & liquids project • Indonesia: seismic in advance Cooper Basin and Indonesia • Patchawarra oil play in Worrior field • Extensive 3D seismic in northern • Otway Basin drilling identifies new conventional gas play and informs shale gas exploration of farm-out • Indonesian production up 120% • Hammamet West-3 adds 11 MMboe Cooper Basin • Increased BAS stake to 22.9% 2C Contingent Resources • Tunisia divestment process 2015 Plans • Base production of 500 – 560 kbbls from Cooper Basin and Indonesia • BMG business case • Complete Tunisia divestment • Exploration and maturation of • Complete Indonesian farm-outs • Appraise Worrior Patchawarra oil play Otway Basin opportunity • Appraise and develop low cost/low • Exploration drilling on 3D seismic in • Gas production focussed risk Sukananti reserves PEL 92, 100, 110 acquisitions • Value-adding oil acquisitions Acquisition of Dundinna seismic survey, northern permits, Cooper Basin (Photo by nadineshaw.com, provided courtesy of Senex Energy Limited) 11 PRODUCTION AND RESERVES Production Cooper Energy’s oil production for the year totalled 0.59 MMbbl, 91% of which was derived from the company’s Cooper Basin tenements. This is a 20% increase on the previous year, primarily as a result of increased production from PEL 92 following a deferment in 2013 and increased production from Indonesia following the successful reinstatement of production at Tangai-1. Production MMbbl Cooper Basin, Australia South Sumatra, Indonesia Total Reserves & Resources Reserves FY14 0.54 0.05 0.59 FY13 0.46 0.03 0.49 Cooper Energy’s 2P Reserves as at 30 June 2014 are assessed to be 2.01 million barrels of oil (MMbbl). This represents a decrease of 0.15 MMbbl from 30 June 2013, driven by record production, partially offset by reserve upgrades in fields in both Australia and Indonesia. Petroleum Reserves at 30 June 2014 MMbbl Category Proved (1P) Proved & Probable (2P) Proved, Probable & Possible (3P) Australia Indonesia Total Australia Indonesia Total Australia Indonesia Total Developed 0.57 Undeveloped 0.14 Total 0.71 0.04 0.10 0.14 0.61 0.24 0.85 1.16 0.38 1.54 0.08 0.39 1.25 0.77 0.47 2.01 1.99 0.62 2.61 0.17 0.63 2.17 1.25 0.81 3.42 Year-on-year movement in Petroleum Reserves MMbbl Proved (1P) Proved & Probable (2P) Proved, Probable & Possible (3P) Reserves at 30 June 2013 1.02 FY14 production (0.59) Reserve added through exploration and revisions Reserves at 30 June 2014 0.42 0.85 2.16 (0.59) 0.45 2.01 3.53 (0.59) 0.48 3.42 12 Contingent Resources 2C Contingent Resources at 30 June 2014 have increased by 29.3 MMboe to an estimate of 35.1 MMboe. The key revisions are the addition of the Hammamet West field, Tunisia, and the Basker and Manta fields in the Gippsland Basin. Contingent Resources at 30 June 2014 Product 1C 2C 3C Australia Tunisia Total Australia Tunisia Total Australia Tunisia Total Gas (BCF) Oil (MMbbl) 40.7 2.8 1.6 8.6 42.3 11.4 67.3 4.7 5.4 16.1 72.7 20.8 117.9 17.9 135.8 7.2 36.3 43.5 Total (MMboe) 10.8 9.0 19.7 18.0 17.0 35.1 30.6 39.5 70.1 2C Contingent Resource MMboe Australia Tunisia Resource at 30 June 2013 Revisions Resource at 30 June 2014 Note: 0.01 18.0 18.0 5.7 11.3 17.0 Total 5.8 29.3 35.1 - Reserves include Cooper Energy’s share of future crude fuel usage in the Cooper Basin. The estimated fuel usage is: 1P, 0.02 MMbbl; 2P, 0.05 MMbbl and 3P, 0.08 MMbbl. There is no produced crude oil used for fuel in Indonesia. - Reserves and Resources categories as well as Basin and company totals are aggregated by arithmetic summation. Totals may not reflect arithmetic addition due to rounding. - Aggregated 1P & 1C may be very conservative estimates and aggregated 3P & 3C may be very optimistic estimates due to the portfolio effects of arithmetic summation. - Contingent Resources assessment includes resources in the Hammamet West Field, in the Bargou Permit, offshore Tunisia, as released to the ASX on 28 April 2014. Cooper Energy is not aware of any new information or data that materially affects the information provided in that release, and all material assumptions and technical parameters underpinning the estimates provided in that release continue to apply and have not changed. - Contingent Resources assessment includes resources in Basker and Manta Fields, in the Gippsland Basin, as released to the ASX on 18 August 2014. Cooper Energy is not aware of any new information or data that materially affects the information provided in that release, and all material assumptions and technical parameters underpinning the estimates provided in that release continue to apply and have not changed. - Cooper Energy carries out an annual assessment of its petroleum reserves and resources using methodology that is in accordance with the SPE Petroleum Resources Management System (SPE-PRMS). This assessment is undertaken by staff of Cooper Energy utilising information provided by relevant Joint Venture Operators, where appropriate. The assessment is reviewed by the Executive Director – Exploration & Production, prior to its approval by the Board of Directors. Qualified petroleum reserves and resources evaluator This report contains information on petroleum reserves and resources which 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 Exploration Manager, holds a Bachelor of Science (Hons), is a member of the American Association of Petroleum Geologists and the Society of Petroleum Engineers and 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. 13 HEALTH SAFETY ENVIRONMENT AND COMMUNITY One of Cooper Energy’s core values is to conduct its operations with due care for health, safety, the environment and the communities in which it works. Cooper Energy staff and contractors worked a total of 1.19 million hours during the year, with just one Lost Time Injury (LTI). A standard industry metric for safety performance is the number of LTI’s per million hours worked or the Lost Time Injury Frequency Rate (LTIFR). Cooper Energy recorded a LTIFR of 0.8 in 2014, in line with the overall Australian upstream petroleum industry benchmark. The LTI occurred when a contractor experienced an allergic reaction to paint thinner and had to be evacuated from a drilling rig offshore Tunisia, with an absence from work of 1.5 days. A particular highlight of HSEC performance was the Sumbagsel 2D seismic acquisition project in South Sumatra, Indonesia which involved a crew of more than 600 people working a total of 537,000 hours over 179 days in challenging swamp conditions without a single LTI. The only safety incidents recorded involved minor lacerations received by two crew clearing jungle vegetation which were resolved onsite with first aid treatment. Also in South Sumatra, the application of HSEC principles to the clean-up of oil interceptor ponds at the Tangai-1 Early Production Facility meant that the costs of the operation were more than recouped through the sale of the 292 barrels of oil recovered in the clean-up. Cooper Energy undertakes a number of programs to assist local communities in the vicinity of its operations in South Sumatra. The company also supports community engagement activities by the Operators in respect of its Cooper Basin and Otway Basin acreage. Cooper Energy will continue to set challenging internal objectives as it strives to achieve continuous improvement in its HSEC performance through the next financial year. The company is planning to broaden its Community involvement in 2015 through a program involving staff in supporting various charitable organisations in our local regions. Evaporation pond and accommodation facilities, Callawonga camp, PEL 92 Cooper Basin 14 REVIEW OF OPERATIONS HECTOR GORDON Overview Cooper Energy’s operations primarily comprise: • oil production in the Cooper Basin (onshore Australia) and the South Sumatra Basin (onshore Indonesia). • onshore oil and gas exploration in the Cooper, Otway and South Sumatra Basins and offshore in the Gippsland Basin and Tunisia. Highlights of the year’s activities were: • record oil production • oil discovery at Hammamet West, offshore Tunisia • new oil pool discovered in the Worrior field, Cooper Basin • new gas play identified in the Penola Trough, Otway Basin • acquisition of 65% in interest in Basker, Manta and Gummy fields in Gippsland Basin 2014 drilling activity Type Area Tenement Well Result Exploration Cooper Basin PEL 92 Hooper-1 PEL 92 Morgan-1 PEL 92 Fishery-1 Otway Basin PEL 495 Jolly-1 P&A P&A P&A P&A PRL 32 Bungaloo-1 Cased and Suspended Tunisia Bargou Hammamet West-3* Oil Discovery Appraisal Cooper Basin PPL 250 Windmill-2 PPL 207 Worrior-10 Development Cooper Basin PPL 245 Butlers-7 PPL 245 Butlers-8 PPL 220 Callawonga-9 PPL 207 Worrior-8 *Hammamet West-3 spudded in April 2013 Oil well Oil well Oil well Oil well Oil well Cased for further evaluation 15 Hector Gordon Executive Director – Exploration and Production In 2014 Cooper Energy’s oil production totalled 0.59 MMbbl, 91% of which was derived from the company’s Cooper Basin tenements. This is the highest annual production ever achieved by the company. Cooper Energy participated in the drilling of 12 wells during the year, one of which, Hammamet West-3 commenced in the previous financial year. The program comprised 6 exploration wells and 6 appraisal/development wells. The exploration program resulted in one new oil field discovery, Hammamet West. All five of the appraisal/ development wells were successful. In addition, a new oil pool discovery within the Worrior field was confirmed by testing of Worrior-8, which was drilled in the previous year. REVIEW OF OPERATIONS COOPER BASIN 139°20' 139°40' 100 101 -27°40' 99 96 Rincon North Rincon Hooper-1 98 k e e r C er p o o C Cooper Energy tenement Other companies tenements Oil field Gas field Oil pipeline Gas pipeline Oil well Plugged and abandoned well 97 93 91 87 95 94 93 98 97 Windmill-2 PRLs 85 to 104 (25%) (ex ‘PEL 92’) 92 Callawonga Callawonga-9 Fishery-1 99 100 86 Windmill 86 90 -28° Parsons 89 Perlubie Butlers 85 Elliston 87 Butlers-7 Butlers-8 Germein 92 85 88 91 90 Sellicks 102 104 103 Lycium Hub Christies Silver Sands Morgan-1 101 0 20 kilometres PEL 93 (30%) Cooper Energy holds interests in 4 exploration licenses, 20 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 86% of Cooper Energy’s total production in 2014. Oil exploration is also being undertaken in the company’s tenements along the northern flank of the basin (PEL’s 90, 100 & 110). *During the year the PEL 92 Joint Venture (Cooper Energy 25%) was granted 6 new Petroleum Production Licences (PPL’s 245 – 250) and 20 Petroleum Retention Licenses (PRL’s 85 – 104), which together cover the entire area previously licenced as PEL 92. Cooper Energy’s share of oil production from its Cooper Basin tenements during the year totalled 0.54 MMbbl, 17% above that achieved in the previous year. This increase was primarily a result of oil export from PEL 92 predominately by pipeline for the full year, in contrast to 2013 during which failure of third party infrastructure resulted in production being constrained by trucking capacity for approximately 6 months. Additionally, production commenced from the Windmill and Rincon fields during the year and 5 new wells were brought online from the Callawonga and Butlers fields. Four oil appraisal/development wells were drilled in the Windmill, Butlers and Callawonga oil fields (PEL 92, Cooper 25%), all of which were completed as oil producers and commenced production during the year. 16 PEL 110 Plan area PEL 100 -27° TAS Worrior-10 Worrior PPL 207 Worrior-8 1 kilometre PRLs 85 to 104 CC oopoo C ooper C errrr CCCCCCC HH PEL 90 G H U Inset R I T R O U G H -28° R M E A P P e e k rr r rr e e A R R A T R O A N W P A T C H A MOOMBA S I N A R B PEL 93 O C E P O 0 40 139° 140° kilometres The highlight of the year’s activities in the Cooper Basin was the confirmation of a new oil pool discovery in the Patchawarra Formation within the Worrior field. Production testing of Worrior-8 (PPL 207, Cooper Energy 30%), which was drilled in July 2013, was undertaken in November 2013 and achieved a stabilised flowrate of 670 barrels of oil per day, accompanied by 0.7 million cubic feet per day of gas. Worrior-10, was subsequently drilled in March 2014 to appraise the north-western extent of the Patchawarra Formation oil accumulation and intersected 4.5 metres of net oil pay and was cased and suspended as a future oil producer. An extended production test is scheduled to commence in the September quarter of 2014. Three oil exploration wells were drilled in the Cooper Basin during the year, all in PEL 92 and all of which were unsuccessful. Fishery-1 encountered a sub-commercial oil column in the Namur Sandstone, which could result in further drilling on that prospect. Acquisition and processing of the Dundinna seismic survey, which commenced in June 2013 and includes a total of 576 km2 of 3D data in PELs 90, 100 and 110, was completed during the year. The results of the Dundinna seismic survey are being used to re-assess the portfolio of prospects and leads in these tenements. Exploration drilling utilising the results of the survey is planned to commence in the first half of 2015. 139°30' 139°30' 139°40' 139°50' -28°20' Worrior Worrior-10 See inset O P E R B A SIN -28°30' -28°40' PEL 93 (30%) Worrior-8 PEL 93 (30%) C O Cooper Energy tenement Other companies tenements Oil field Gas field Oil pipeline Gas pipeline Oil well Oil show 140°20' Cooper Energy tenement Other companies tenements Oil field Gas field Oil pipeline Gas pipeline 3D seismic survey 0 20 kilometres 140°40' PEL 110 (20%) -27°00' 0 10 20 kilometres Dundinna 3D seismic survey PEL 100 (19.17%) Tarragon Cleansweep ' 0 0 ° 7 2 - Kiwi Keleary Telopea PEL 90 (25%) 17 REVIEW OF OPERATIONS OTWAY BASIN Kingston SE SOUTH AUSTRALIA PEL 186 (33%) Naracoorte PEL 495 (30%) ROBE TROUGH Robe ST CLAIR TROUGH Beachport PEP 171 (25%) Bungaloo-1 Katnook Penola Jolly-1 Plan area TAS VICTORIA P E N O L A PEL 494 (30%) Millicent PRL 32 (30%) T R O U G H Mount Gambier PEP 150 (20%) Hamilton ARDONAC HIE T R O U G H 0 20 40 kilometres Cooper Energy tenement Gas field Gas pipeline Depositional trough Plugged and abandoned well Well with gas show PEP 151 (75%) Portland PEP 168 (50%) Cobden Warrnambool East Wing 1 Cooper Energy holds interests in 8 exploration licences in the onshore Otway Basin covering a total area of 10,191 km2. The company’s primary focus in this region has been exploration for unconventional oil and gas plays associated with the Casterton and Sawpit Formations, primarily within the Penola Trough. During the year agreements were finalised with Native Title claimants over the areas covered by PEP 150 (Cooper Energy 20%) and PEP 171 (Cooper Energy 25%) in western Victoria and these tenements were granted to Cooper Energy and its Joint Venture participants in August 2013. Cooper Energy also acquired a 30% interest in tenements PEL 494 and PRL 32 during the year from Beach Energy Limited and simultaneously divested a 35% equity in the adjoining PEL 495 tenement to that company. The result of these transactions, which involved zero net cost to Cooper Energy, is that the company holds a 30% equity across the key tenements in the South Australian section of the Penola Trough. Two deep wells were drilled in the South Australian portion of the basin during the year, with the primary aim of assessing unconventional gas plays in the Casterton and Sawpit Formations in the Penola Trough. Jolly-1 was drilled to a total depth of 4,026 metres in PEL 495 (Cooper Energy 30%) and is the deepest petroleum well to date in the onshore Otway Basin. Although the well was drilled outside interpreted structural closure, elevated mud gas readings were observed over a gross interval of 340 metres of the Lower Sawpit Shale, which contains extensive sandstone intervals. A total of 78 metres of conventional core was recovered from the Sawpit and Casterton Formations. Bungaloo-1 was drilled to a total depth of 3,713 metres in PRL 32 (Cooper Energy 30%) and was also located in a position interpreted to be outside structural closure. A total of 103 metres of conventional core was recovered from the Sawpit and Casterton Formations. Elevated mud gas readings and hydrocarbon fluorescence were observed over a gross 143 metre interval within sandstone intervals of the Lower Sawpit Shale. Gas shows were also encountered over a 411 metre gross interval in the Casterton Formation and Basement. 18 Important core data was gathered during the Jolly-1 and Bungaloo-1 operations and this will be used to further assess the potential of unconventional plays in the Casterton and Sawpit Formations. Additionally, and perhaps more significantly, the presence of significant hydrocarbon shows in sandstones over large vertical intervals in wells that are interpreted to be located off-structure, indicates the possible presence of a basin- centred gas play in sandstones deep in the Penola Trough. The data and cores obtained from the two wells are being analysed to build further understanding of the gas potential of the Penola Trough before the respective joint ventures make decisions on the next steps of the exploration program. Acquisition of 2D seismic was undertaken in PEPs 168 (162 km) and PEP 151 (112 km). REVIEW OF OPERATIONS GIPPSLAND BASIN During the year Cooper Energy acquired a 65% interest in the Basker, Manta and Gummy oil and gas fields in the offshore Gippsland Basin. In conjunction with this acquisition, Cooper Energy was appointed Operator of the BMG Joint Venture. The Basker and Manta fields were previously developed for oil production (which included gas production and re-injection) and have been in a non-productive phase since 2010. A potentially economic volume of gas and oil remains to be recovered and its evaluation will be the focus of the BMG Joint Venture. Cooper Energy’s assessment of the Contingent Resources in the Basker and Manta fields are presented in the table opposite. Prospective resources of oil and gas are also recognised in the Gummy and Chimera structures. The next phase of work in the BMG project will be the preparation of the business case to support further activity in the tenements, which may include appraisal drilling in FY16. In July 2013 Cooper Energy executed conditional farm-in agreements under which it could acquire a 50% interest in VIC/P68 and 25.8% interest in VIC P/41, both located in the offshore Gippsland Basin. However, these agreements were not approved by the shareholders at the Annual General Meeting of the Bass Strait Oil Company Limited and the farm-ins did not proceed. Contingent Resource in the Basker and Manta fields, Gippsland Basin Gross Contingent Resource1 Oil & Condensate MMbbl Gas Total PJ MMboe Net Contingent Resource for Cooper Energy Oil & Condensate MMbbl Gas Total PJ MMboe 1C 4.3 72.2 16.7 2.8 46.9 10.8 2C 7.2 119.4 27.7 4.7 77.6 18.0 3C 11.1 209.1 47.0 7.2 135.9 30.6 1 This assessment was detailed and discussed in an announcement to the ASX on 18 August 2014. VICTORIA Plan area TAS Orbost Orbost gas plant Lakes Entrance Moby Patricia-Baleen Longtom VIC/P68 Leatherjacket Snapper Tuna Kipper Marlin Flounder Manta Gummy Sole VIC/P41 Fortescue Kingfish VIC/L27 (65%) Basker VIC/L28 (65%) VIC/L26 (65%) Cooper Energy tenement BAS tenement Oil field Gas field Oil pipeline Gas pipeline Highway Road 0 20 kilometres 19 REVIEW OF OPERATIONS INDONESIA 103° 00' E 104° 00' E Kaliberau Meruap Piano Gambang Suban Tampi Merangin III PSC (100%) 3° 00' S INDONESIA 0 25 50 kilometres 4° 00' S Cooper Energy holds interests and operates 3 tenements in the onshore South Sumatra Basin. Sukananti KSO Cooper Energy is the 55% interest holder and Operator of the Sukananti KSO. Cooper Energy’s share of production from the Sukananti KSO during the year totalled 0.05 MMbbl, an increase of 0.02 MMbbl on the previous year, resulting from improved performance from Bunian-1 and a full year’s production from Tangai-1. In June 2014 Sukananti-1, which was a non-producing well, was recompleted as a water injection well, increasing field water disposal capacity by a factor of more than 5 and hence eliminating an existing oil production constraint. Subsequent to year-end, workover of Tangai-3 was successfully undertaken, resulting in oil flows from two zones at combined initial rates of approximately 100 bopd. The well commenced oil production, on natural flow through temporary facilities, in July 2014. It is expected that the production rate will be increased by the installation of artificial lift in 2015. Tanjung Miring Barat 104°55' JAVA SEA Bunian Bunian-1 INDONESIA Bunian-3 Bunian-4 Tangai-3 Tangai-5 -3°35' Tangai-1 Tangai Sukananti KSO (55%) Palembang Sungai Gerong Plaju Refinery Sumbagsel PSC (100%) 0 2 kilometres SOUTH CHINA SEA MALAYSIA I N D O N E S I A Sumarta South Sumatra Basin JAVA SEA JJ INDIAN OCEAN Sukananti KSO (55%) Cooper Energy tenement Oil field Gas field Pipeline Oil well Suspended oil well Abandoned oil well Plugged and abandoned well Proposed well Sumbagsel PSC Cooper Energy is the 100% interest holder and Operator of the Sumbagsel PSC which lies on the eastern flank of the basin and contains a wide prospect inventory of both shallow oil and deeper gas prospects and leads. Acquisition and processing of 257 km of 2D seismic was undertaken in the year, the objective of which was to delineate exploration targets for drilling in 2015. Cooper Energy will seek to farm-out a portion of its equity in the Sumbagsel PSC following interpretation of the seismic data. Merangin III PSC Cooper Energy is the 100% interest holder and Operator of the Merangin III PSC which lies in the central portion of the basin and contains a wide prospect inventory of both shallow oil and deeper gas prospects and leads. Reprocessing of over 1,322 km of 2D seismic data from the Merangin III PSC was completed during the year, with the objective of maturing targets for seismic acquisition in calendar 2015. Drilling of 3 development wells, Bunian-3, Bunian-4 and Tangai-5 is expected to commence in late 2014. Cooper Energy will seek to farm-out a portion of its equity in the Merangin III PSC following interpretation of the seismic data. 20 REVIEW OF OPERATIONS TUNISIA 10°E 37°N Tunis 36°N 11°E 12°E 13 E 13°E Bargou Permit (30%) Hammamet Permit (35%) Lambouka Dougga Pantelleria Island (Italy) MEDITERRANEAN SEA Map area TUNISIA Hammamet West-3 Aster Zibibbo Neopolis Tazerka Yasmin Birsa Maamoura Fushia Tafernine Zelfa Baraka Baraka SE Baraka South Sousse Monastir TUNISIA Cosmos Oudna Lotus Sbeitla El Mediouni Halk El Menzel 0 50 kilometres Nabeul Permit (85%) Cooper Energy tenement Oil field Gas field Gas pipeline Oil well Cooper Energy holds interests and operates 3 tenements in the Pelagian Basin, offshore Tunisia. These tenements surround existing producing fields, include undeveloped resources and contain an extensive inventory of exploration prospects and leads. Bargou Permit Cooper Energy is the 30% interest holder and Operator of the Bargou Permit. Drilling of Hammamet West-3, which spudded in April 2013, was completed during the year. A 432 metre horizontal sidetrack section was drilled within the Abiod Formation, during which major gas and oil influxes and major drilling mud losses were experienced, indicating that the well had penetrated open hydrocarbon bearing fractures within the Abiod Formation. Contingent Resource in the Abiod Formation, Hammamet West Field, offshore Tunisia Gross1 Contingent Resource Oil Gas Total MMbbl Bcf MMboe Net Contingent Resource for Cooper Energy Oil Gas Total MMbbl Bcf MMboe Production testing of the well commenced in August 2014 and confirmed the presence of open hydrocarbon bearing fractures. The production testing could not be completed due to ongoing blockages and obstructions caused by lost circulation material. During testing the well recorded flow rates averaging 1,290 barrels of fluid per day for 1.5 hours, including oil to surface. The well was plugged and suspended as an oil discovery in November 2013. It is planned to return to Hammamet West-3 in 2015 to drill and test a second near horizontal side track to fully assess the hydrocarbons encountered in the previous wellbore. The Contingent Resource assessment has reinforced confidence in the likelihood of the commercial development of the Hammamet West field. The gross 1C Contingent Resource assessed for the field of 11.6 MMbbl of oil exceeds the threshold of 8 to 10 MMbbl reserves of oil that Cooper Energy’s calculations indicate is required for the field to be considered economic. The drilling and production testing of the second sidetrack on Hammamet West-3 is expected to provide key information for further assessment of the resource base and development options. Hammamet Permit Following the drilling and testing of Hammamet West-3, Cooper Energy prepared an assessment of the Contingent Resource of the Hammamet West discovery which is provided in the table below. Activity in the Hammamet and Nabeul permits during the year consisted of seismic reinterpretation and geological studies, aimed at maturing prospects for drilling in 2015. Poland Cooper Energy has withdrawn from and exited the company’s remaining tenements in Poland. 1C 11.6 5.3 12.6 3.5 1.6 3.8 2C 34.5 17.9 37.7 10.4 5.4 11.3 3C 99.8 59.7 110.4 29.9 17.9 33.1 1 This assessment was detailed and discussed in an announcement to the ASX on 28 April 2014. 21 PORTFOLIO EXPLORATION AND PRODUCTION TENEMENTS Region: Australia Cooper Basin State Tenement Interest Location Area (km2) Operator Activities South Australia PPL 204 (Sellicks) 25% Onshore 2.0 Beach Energy Production PPL 205 (Christies / Silver Sands) PPL 207 (Worrior) PPL 220 (Callawonga) PPL 224 (Parsons) PPL 245 (Butlers) PPL 246 (Germein) PPL 247 (Perlubie) PPL 248 (Rincon) PPL 249 (Elliston) PPL 250 (Windmill) PEL 90 (Kiwi sub-block) PEL 921 (PRL’s 85 – 104) PEL 93 PEL 100 PEL 110 25% 30% 25% 25% 25% 25% 25% 25% 25% 25% 25% 25% 30% Onshore Onshore Onshore Onshore Onshore Onshore Onshore Onshore Onshore Onshore Onshore 4.3 6.4 5.5 1.8 2.1 0.1 1.5 2.0 0.8 0.6 Beach Energy Production Senex Energy Production Beach Energy Production Beach Energy Production Beach Energy Production Beach Energy Production Beach Energy Production Beach Energy Production Beach Energy Production Beach Energy Production 145.0 Senex Energy Exploration Onshore 1,889.3 Beach Energy Exploration Onshore 621.8 Senex Energy Exploration 19.17% Onshore 296.5 Senex Energy Exploration 20% Onshore 727.5 Senex Energy Exploration Otway Basin State Tenement Interest Location Area (km2) Operator Activities South Australia PEL 186 33% 30% 30% 30% 20% 75% 50% 25% Onshore 709.1 Cooper Energy Exploration Onshore 1,765.7 Beach Energy Exploration Onshore Onshore 793.3 Beach Energy Exploration 36.9 Beach Energy Exploration Onshore 3,212.0 Beach Energy Exploration Onshore Onshore 863.8 Bridgeport Energy Exploration 795.0 Beach Energy Exploration Onshore 1,974.0 Beach Energy Exploration PEL 494 PEL 495 PRL 32 PEP 150 PEP 151 PEP 168 PEP 171 Victoria Gippsland Basin State Victoria Tenement Interest Location Area (km2) Operator Activities VIC/L26 VIC/L27 VIC/L28 65% 65% 65% Offshore Offshore Offshore 67.0 67.0 67.0 Cooper Energy Production Cooper Energy Production Cooper Energy Production 1 Granted on 6 June 2014, PRL’s; 85, 86, 87, 88, 89, 90, 91, 92, 93, 94, 95, 96, 97, 98, 99, 100, 101, 102, 103 and 104, these retention licenses make up the area previously known as PEL 92. 22 Region: Indonesia South Sumatra Basin Tenement Interest Location Area (km2) Operator Sukananti KSO Sumbagsel PSC Merangin III PSC Region: Tunisia Gulf of Hammamet Tenement Bargou Hammamet Nabeul 55% 100% 100% Onshore Onshore Onshore 18.3 1,753 1,488 Cooper Energy Cooper Energy Cooper Energy Interest Location Area (km2) Operator 30% 35% 85% Offshore Offshore Offshore Activities Production Exploration Exploration Activities Exploration 4,616 4,676 Cooper Energy Storm Ventures International Exploration 3,352 Cooper Energy Exploration Butlers oil field facilities, PRL 85 Cooper Basin 23 24 KEY PERFORMANCE INDICATORS Operational Wells drilled Exploration wells spudded Exploration success rate 12 months to 30 June number number percent Cumulative exploration success rate percent FY08 FY09 FY10 FY11 FY12 FY13 FY14 13 6 17% 21% 0.38 1.44 45.0 3.7 15.8 15.8 6.4 64.6 - 73.6 26.0 9.3 7 5 60% 30% 0.49 1.91 4 4 0% 27% 0.47 2.00 41.6 40.0 4.2 5.2 5.0 -2.8 93.4 - 96.5 23.2 17.7 4.3 8.0 7.2 1.2 92.5 - 95.4 24.4 25.7 12 6 0% 23% 0.41 2.47 39.1 5.1 -6.0 -5.5 -10.3 72.4 - 79.5 14.1 31.4 10 6 50% 27% 0.52 1.88 59.6 4.7 9.1 21.0 8.4 61.5 13.2 53.4 22.5 37.0 13 8 25% 26% 0.49 2.16 53.4 2.3 22.3 18.3 1.3 47.9 20.2 51.7 23.8 39.0 115.5 123.3 125.1 114.9 136.9 137.2 2.9 -1.0 0.4 -3.5 2.8 0.4 11 5 0% 24% 0.59 2.01 72.3 2.8 36.9 31.2 22.0 49.1 26.0 41.2 45.7 38.7 167.8 6.4 5.5% -2.3% 1.0% -8.6% 6.7% 0.9% 14.4% -41.1% -3.2% -17.8% -2.7% 25.0% -16.7% 34.7% 118.46 86.76 87.02 95.42 114.63 112.31 124.08 MMbbl MMbbl $ million $ million $ million $ million $ million $ million $ million $ million $ million $ million $ million cents percent percent A$/bbl $ per share 0.465 0.45 0.37 0.36 0.45 0.375 million $ million number 252.3 291.9 292.6 292.6 327.3 329.1 117.3 131.4 108.3 105.3 147.3 123.4 7,345 7,596 6,537 5,573 5,485 5,284 0.505 329.2 166.3 5,122 Annual production Proved & Probable Reserves Financial Oil sales revenue Other revenue EBITDA Profit before tax Profit after tax Cash & term deposits Investments available for sale Working capital Accumulated profit Cumulative franking credits Shareholders equity Earnings per share Return on shareholders funds Total shareholder return Average oil price Capital as at 30 June Share price Issued shares Market capitalisation Shareholders Opposite image: drilling Bungaloo-1, PRL 32 , Otway Basin, South Australia 25 BOARD OF DIRECTORS 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, a 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 currently Chairman of Bupa Australia (since 2008), the Sydney Symphony (since 2007) and 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) and AFC Asian Cup (2015) (since 2012). Mr Conde is a former Chairman of Ausgrid (formerly EnergyAustralia) (1988-2012) and Destination NSW (2011 – 2014). Special Responsibilities Mr Conde is a member of the Remuneration and Nomination Committee and the Audit and Risk Committee. Mr Jeffrey W. Schneider B.Com Ms Alice J.M. Williams B.Com, FAICD, FCPA, CFA Independent Non-Executive Director Independent Non-Executive Director Appointed 12 October 2011 Appointed 28 August 2013 Experience and expertise Mr Schneider has over 30 years of experience in senior management roles in the oil and gas industry, including 24 years with Woodside Petroleum Limited. He has extensive corporate governance and board experience as both a non-executive director and chairman in resources companies. Current and other directorships in the last 3 years Mr Schneider is a non-executive director of Comet Ridge Limited ASX: COI (since 2003). Mr Schneider was formerly a director of Green Rock Energy Limited ASX: GRK (2010 - 2013). Special Responsibilities Mr Schneider is Chairman of the Remuneration and Nomination Committees and member of the Audit and Risk Committee. Experience and expertise Ms Williams has over 25 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 and Western Health. Current and other directorships in the last 3 years Ms Williams is a non-executive Director of Djerriwarrh Investments Ltd ASX: DJW (since 2010), Equity Trustees Ltd ASX: EQT (since 2007), Victorian Funds Management Corporation, Guild Group, Defence Health and Port of Melbourne Corporation. Ms Williams is also a Council member of the Cancer Council of Victoria. Special Responsibilities Ms Williams is Chairman of the Audit and Risk Committee and a member of the Remuneration and Nomination Committee. 26 Mr David P. Maxwell M.Tech, FAICD Managing Director Mr Hector M. Gordon B.Sc. (Hons). FAICD Executive Director Appointed 12 October 2011 Appointed 26 June 2012 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 successfully led many large commercial, marketing and business development projects. Mr Maxwell has served on a number of industry association boards, government advisory groups and public company boards. He was a member of the Australia Federal Government Energy White Paper Reference Group in 2011. Current and other directorships in the last 3 years Mr Maxwell is a director of Somerton Energy Pty Ltd formerly Somerton Energy Ltd, a listed company until the takeover by Cooper Energy in 2012. Special Responsibilities Mr Maxwell is responsible for the day to day leadership of Cooper Energy. He is the leader of the management team and his particular responsibilities include strategy and business development. Experience and expertise Mr Gordon is a very successful geologist with over 35 years’ 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 Somerton Energy Pty Ltd formerly Somerton Energy Ltd, a listed company until the takeover by Cooper Energy in 2012. He is a former director of ERO Mining Limited (2011-2013). Special Responsibilities As a part time executive of the Company, Mr Gordon is responsible for overseeing exploration and production activities and providing technical expertise in these areas. He is also Chairman of the HSEC Management Committee and the Indonesia Management Committee. 27 EXECUTIVE MANAGEMENT TEAM Iain MacDougall BSc (Hons) Operations Manager Andrew Thomas BSc (Hons) Exploration Manager Hector M. Gordon BSc (Hons), F.A.I.C.D. Executive Director – Exploration & Production David Maxwell M.Tech, FAICD Managing Director Alison Evans B.A., LLB Company Secretary and Legal Counsel Eddy Glavas B.Acc., CPA, MBA Commercial & Business Development Manager Jason de Ross B.Ec., ACA, MBA, F Fin Chief Financial Officer, Company Secretary 28 COOPER ENERGY LIMITED AND ITS CONTROLLED ENTITIES FINANCIAL REPORT FOR THE YEAR ENDED 30 JUNE 2014 ABN 93 096 170 295 OPERATING AND FINANCIAL REVIEW DIRECTORS’ STATUTORY 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. 2. 3. 4. 5. 6. 7. 8. 9. Corporate Information Summary of Significant Accounting Policies Segment Reporting Revenues and Expenses Income Tax Earnings Per Share Cash and Cash Equivalents and Term Deposits Trade and Other Receivables (Current) Prepayments (Current) 10. Exploration Assets Held for Sale and Discontinued Operations 11. Available for Sale Investment (Non-Current) 12. Oil Properties (Non-Current) 13. Other Property, Plant & Equipment (Non-Current) 14. Exploration and Evaluation (Non-Current) 15. Trade and Other Payables (Current) 16. Provisions (Non-Current) 17. Financial Liabilities (Non-Current) 18. Contributed Equity and Reserves 19. Financial Risk Management Objectives and Policies 20. Commitments and Contingencies 21. Interests in Joint Arrangements 22. Related Parties 23. Share Based Payment Plans 24. Auditors’ Remuneration 25. Parent Entity Information 26. Events After the Reporting Period DIRECTORS’ DECLARATION INDEPENDENT AUDIT REPORT AUDITORS’ INDEPENDENCE DECLARATION 30 34 52 53 54 55 56 56 56 69 72 73 75 76 77 77 77 78 78 79 79 80 80 80 81 82 86 87 88 90 92 92 93 94 95 97 SECURITIES EXCHANGE AND SHAREHOLDER INFORMATION 98 CORPORATE DIRECTORY Inside back cover 29 OPERATING AND FINANCIAL REVIEW For the year ended 30 June 2014 Operations Cooper Energy is a petroleum exploration and production company which generates revenue, free cash flow and profit from the discovery, development and sale of hydrocarbons in Australia and Indonesia. The Company concentrates its resources and efforts on opportunities to supply the Australian energy market and oil and gas exploration and production activities in the South Sumatra Basin, Indonesia. Cooper Energy currently produces oil from the Cooper Basin, Australia and the South Sumatra Basin, Indonesia. The Cooper Basin accounted for 91% of the Company’s oil production in the twelve months to June 30, 2014 (“FY14”) of 0.59 million barrels of oil. This was 20% higher than the previous year’s production of 0.49 million barrels of oil due to increases in output from Cooper Basin and Indonesian operations. Cooper Energy holds interests in petroleum exploration tenements in the Cooper Basin, Otway and Gippsland Basins in Australia, the South Sumatra Basin in Indonesia and the Pelagian Basin offshore Tunisia. The Company also holds 22.9% of the issued share capital of Bass Strait Oil Company Limited which has interests in exploration tenements in the Gippsland Basin and Otway Basins. Exploration and development activity during the period included: • the drilling of five successful development wells and three unsuccessful exploration wells in the Cooper Basin. • the drilling of two deep exploration wells in the Penola Trough of the South Australian Otway Basin to assess the hydrocarbon potential of the Sawpit and Casterton Formations. The wells provided encouragement for further gas exploration in this region and the information obtained is being assessed to determine future exploration plans. • seismic acquisition in the Cooper Basin (PEL 90, 100 and 110) and South Sumatra Basin (Sumbagsel PSC) to identify targets for future drilling. Seismic data from South Sumatra Basin (Merangin III PSC) was reprocessed during the year. • the casing and suspending of Hammamet West-3, which was spudded offshore Tunisia in April 2013 and completed in October 2013. The well, which discovered an oil and gas resource included in the Company’s year-end assessment of its Reserves and Resources, was cased and suspended for future production testing after repeated blockages prevented production testing of the well’s side-track (ST-1). It is intended that the well be subjected to production testing after a second side-track, (ST-2) is drilled. The Company has previously announced its intention to divest its portfolio of Tunisian acreage and the sales process initiated during the year is ongoing. During the year Cooper Energy acquired a 65% interest in the Basker, Manta and Gummy oil and gas fields (BMG) in the offshore Gippsland Basin. In conjunction with this acquisition Cooper was appointed as Operator of the BMG Joint Venture. The Basker and Manta fields were previously developed for oil production (which included gas production and re-injection) and have been in a non-productive phase since 2010. A potentially economic volume of gas and oil remains to be recovered and its evaluation will be the focus of the BMG Joint Venture. The next step in the project will be preparation of the Business Case to support the next phase of activity in the tenements, which may include appraisal drilling in FY16. During the year Cooper Energy acquired a 30% interest in tenements PEL 494 and PRL 32 from Beach Energy Limited and simultaneously divested a 35% equity in the adjoining PEL 495 tenement to that company. The result of these transactions, which involved zero net cost to Cooper Energy, was for the company to hold a 30% equity across the key tenements in the South Australian section of Penola Trough. In addition, the award of the Victorian permits PEP 171 and PEP 151 during the year has extended the coverage of the Company’s acreage across the eastern section of the Penola Trough within the Victorian portion of the Otway Basin. The Company concluded the year with slightly lower Reserves but substantially increased Contingent Resources. Estimated Proved and Probable Reserves as at 30 June were estimated to be 2.01 million barrels of oil, compared with 2.16 million the previous year. The movement reflects the record production in FY14 and exploration results. 2C Contingent Resources of 35.1 million barrels of oil equivalent were higher than the FY13 comparative of 5.74 million barrels of oil equivalent with the increase being attributable to the addition of resource estimates for the BMG gas and liquids resource and the Hammamet West field. Financial Performance Financial Performance Production volume Sales volume Average oil price Sales revenue Other revenue Operating cash flow Net profit after income tax (NPAT) Underlying NPAT Underlying EBITDA* Underlying EBITDA*/Sales revenue MMbbl MMbbl $/bbl $million $million $million $million $million $million % FY14 0.59 0.58 124.1 72.3 2.8 50.3 22.0 25.3 40.2 55.6 FY13 0.49 0.48 112.3 53.4 2.3 12.5 1.3 12.7 22.7 42.5 Change 0.10 0.10 11.8 18.9 0.5 37.8 20.7 12.6 17.5 13.1 % 20% 21% 11% 35% 22% 302% 1592% 99% 77% 31% * Earnings before interest, tax, depreciation and amortisation 30 OPERATING AND FINANCIAL REVIEW For the year ended 30 June 2014 Calculation of underlying NPAT by adjusting for items unrelated to the ongoing operating performance is considered to enable meaningful comparison of results between periods. Underlying NPAT and underlying EBITDA are not defined measures under International Financial Reporting Standards and are not audited. Reconciliations for NPAT to Underlying NPAT and Underlying EBITDA are included at the end of this review. Underlying NPAT for the period was $25.3 million, a $12.6 million increase on the previous corresponding period (pcp) mainly due to: • higher sales revenue, $18.9 million, due mainly to higher oil volumes and a higher average oil price; • higher other revenue, $0.5 million with higher joint venture fees partially offset by lower interest revenue from lower average cash balances and interest rates; and • lower exploration and evaluation expenditure written off, $0.2 million. These factors have been partially offset by: • higher cost of sales, $2.5 million, due to higher oil volumes; • higher administration and other costs, $1.1 million, mainly due to increased new ventures and corporate activity partially offset by lower rent; and • higher income tax expense $3.4 million associated with the higher profit before tax. Financial Position Financial Position Total Assets Total Liabilities Total Equity Total Assets $million $million $million FY14 248.3 80.5 167.8 FY13 162.1 24.8 137.2 Change 86.2 55.7 30.6 % 53% 225% 22% Total assets increased by $86.2 million from $162.1 million to $248.3 million. Cash and deposits increased by $1.2 million from $47.9 million to $49.1 million with cash flow from operations $50.3 million partially offset by cash flows from investing and financing activities $49.5 million as summarised in the following chart. $ million Total Cash & Investments $68.1 Investments (at Fair Value) Cash & deposits 20.2 47.9 81.0 32.4 0.3 1.4 98.2 49.3 Total Cash & Investments $75.1 Investments (at Fair Value) 26.0 Operating +$50.3 0.1 0.3 49.1 Investing, Financing & FX -$49.5 Cash & deposits June 13 Receipts Payments Tax Interset Operating E & D Other Investment Financing June 14 & FX Investments available for sale at fair value increased by $5.8 million from $20.2 million to $26.0 million due to unrealised fair value adjustments. Exploration and evaluation (including those held for sale) increased $86.8 million from $54.7 million to $141.5 million for the exploration and evaluation activities during the period as detailed in the Operations section of this report including the acquisition of BMG exploration assets of $42.4 million. Trade and other receivables decreased $8.6 million from $19.5 million to $10.9 million mainly due to the timing of sales revenue receipts being favourable relative to a three year average. 31 OPERATING AND FINANCIAL REVIEW For the year ended 30 June 2014 Total Liabilities Total liabilities increased by $55.7 million from $24.8 million to $80.5 million. Income tax payable increased by $5.0 million from $nil to $5.0 million after fully utilising income tax losses carried forward from FY13. Net deferred tax liabilities increased by $5.3 million from $9.1 million to $14.4 million mainly due to utilisation of the deferred tax asset booked in respect of the FY13 income tax loss and timing differences including the upfront deductibility of exploration expenditure. Provisions increased by $38.1 million from $3.3 million to $41.4 million mainly due to the acquisition of the BMG abandonment provision of $36.6 million. Financial liabilities increased by $4.0 million from $nil to $4.0 million due to the acquisition of BMG success fee liability of $4.0 million. Total Equity Total equity has increased by $30.6 million from $137.2 million to $167.8 million. In comparing equity for the year to the previous year, the key movements were: • higher reserves, $7.4 million mainly due to the unrealised fair value adjustment on investments available for sale and for share based payments (performance rights); and • higher retained profits, $22.0 million due to total profit for the year. Business Strategies and Prospects The Company focuses its resources and effort on opportunities to supply the Australian energy market and oil and gas exploration in its existing acreage in the South Sumatra Basin, Indonesia. Within these areas of interest, Cooper Energy seeks to focus on those opportunities which satisfy fundamental commercial and technical merit criteria whilst taking due care for safety, the environment and community. In particular, Cooper Energy seeks to generate and add value through the application of its deep knowledge and expertise in Australian basins and gas commercialisation, and concentrating its efforts on the opportunities where its knowledge and expertise can be best applied. The Company’s oil production on the western flank of the Cooper Basin generates high margin cash flow which is being reinvested in: the replacement, and development of oil reserves; exploration for commercial hydrocarbon reserves in the Cooper Basin, the Otway Basin and the Gippsland Basin; and corporate opportunities that add production or which add to the development of a portfolio-style gas supply business. The Otway and Gippsland Basin interests in particular are considered to be well located for available gas market opportunities should reserves of sufficient size be established. Accordingly, the Company has identified the commercialisation of the BMG gas resource in the Gippsland basin and the addressing of the conventional and shale gas opportunity in the Otway Basins as priorities in its gas business development strategy. In Indonesia, the focus is on adding further value to the existing South Sumatra acreage through exploration, development and production. 2015 Outlook and Prospects Cooper Energy has provided market guidance that production in FY15 is expected to be in the range of 0.50 million barrels of oil to 0.56 million barrels of oil (exclusive of exploration success or significant production interruption). Exploration and development plans for FY15 include the drilling of 20 wells and anticipated expenditure of approximately $40 million. The FY15 program represents the Company’s largest drilling commitment yet and comprises 14 exploration or appraisal wells and 6 development wells. The program provides opportunities for reserve and resource additions in the Cooper Basin, where 13 exploration and appraisal wells are planned, and in Indonesia. Drilling in the Cooper Basin is expected to include approximately 5 exploration wells in the lightly explored northern permits PEL 90K, 100, and 110 which were subject to three-dimensional seismic survey In FY14. In Indonesia, the Company plans to drill its first exploration well in the Sumbagsel permit. It remains the Company’s intention to divest its Tunisian portfolio. Divestment options will be assessed against the risk weighted value increment anticipated from achieving a satisfactory production test on the Hammamet West discovery from ST-2 scheduled for drilling on the field in the first half of calendar 2015. Cooper Energy will continue actively to evaluate acquisition opportunities which fit with the Company’s strategy and add value for shareholders. Funding and Capital Management When managing funding and capital, the Company’s objective is to ensure the entity continues as a going concern whilst maintaining an optimal return to shareholders. As at 30 June 2014 the Company had cash, deposits and investments available for sale of $75.1 million. The capital program for FY15 is fully funded from existing cash and operating cash flow. The Company has no debt and $40 million in bank facilities subject to certain conditions. The Company has no current plans to issue equity except as performance rights held by employees meeting vesting conditions. 32 OPERATING AND FINANCIAL REVIEW For the year ended 30 June 2014 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 (including projects by internal auditors) and a summary is reported to the Audit and Risk Committee. Key risks which may materially impact the execution and achievement of the business strategies and prospects for Cooper Energy in future financial years are risks inherent in the oil and gas industry including technical, economic, commercial, operational, environmental and political risks. These risks should not be taken to be a complete or exhaustive list of risks. 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 help manage these risks. Reconciliations for NPAT to Underlying NPAT and Underlying EBITDA Reconciliation to Underlying NPAT Net profit after income tax (NPAT) Adjusted for: Impairment of exploration assets held for sale Impairment of available for sale financial assets PRRT derecognised / (recognised) Underlying NPAT Reconciliation to Underlying EBITDA $million $million $million $million $million FY14 22.0 0.2 3.1 0.0 25.3 FY13 1.3 0.4 0.0 11.0 12.7 Change % 20.7 1592% -0.2 3.1 -11.0 12.6 -50% 100% -100% 99% Underlying NPAT Add back: Interest revenue Tax expense Depreciation Amortisation Underlying EBITDA $million 25.3 12.7 12.6 99% $million $million $million $million $million -1.4 9.0 0.5 6.8 40.2 -2.0 5.6 0.3 6.1 22.7 0.6 3.4 0.2 0.7 17.5 -29% 62% 71% 12% 77% * Earnings before interest, tax, depreciation and amortisation 33 DIRECTORS’ STATUTORY REPORT For the year ended 30 June 2014 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 2014, and the independent auditor’s report thereon. 1. Directors The Directors of the parent entity at any time during or since the end of the financial year are: Mr John C. Conde AO B.Sc. B.E(Hons), MBA Chairman Independent Non-Executive Director Appointed 25 February 2013 Mr David P. Maxwell M.Tech, FAICD Managing Director Appointed 12 October 2011 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, a 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 currently Chairman of Bupa Australia (since 2008), the Sydney Symphony (since 2007) and 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) and AFC Asian Cup (2015) (since 2012). Mr Conde is a former Chairman of Ausgrid (formerly EnergyAustralia) (1988-2012) and Destination NSW (2011 – 2014). Special Responsibilities Mr Conde is a member of the Remuneration and Nomination Committee and the Audit and Risk 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. As Senior Vice President at QGC - a BG Group business – Mr Maxwell 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 has served on a number of industry association boards, government advisory groups and public company boards. He was a member of the Australia Federal Government Energy White Paper Reference Group in 2011. Current and other directorships in the last 3 years Mr Maxwell is a director of Somerton Energy Pty Ltd formerly Somerton Energy Ltd, a listed company until the takeover by Cooper Energy in 2012. Special Responsibilities Mr Maxwell is responsible for the day to day leadership of Cooper Energy. He is the leader of the management team and his particular responsibilities include strategy and business development. 34 DIRECTORS’ STATUTORY REPORT For the year ended 30 June 2014 Mr Jeffrey W. Schneider B.Com Independent Non-Executive Director Experience and expertise Mr Schneider has over 30 years of experience in senior management roles in the oil and gas industry, including 24 years with Woodside Petroleum Limited. He has extensive corporate governance and board experience as both a non-executive director and chairman in resources companies. Appointed 12 October 2011 Current and other directorships in the last 3 years Ms Alice J.M. Williams B.Com, FAICD, FCPA, CFA Independent Non-Executive Director Appointed 28 August 2013 Mr Hector M. Gordon B.Sc. (Hons). FAICD Executive Director Appointed 26 June 2012 Mr Schneider is a non-executive director of Comet Ridge Limited ASX: COI (since 2003). Mr Schneider was formerly a director of Green Rock Energy Limited ASX: GRK (2010 - 2013). Special Responsibilities Mr Schneider is Chairman of the Remuneration and Nomination Committees and member of the Audit and Risk Committee. Experience and expertise Ms Williams has over 25 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 and Western Health. Current and other directorships in the last 3 years Ms Williams is a non-executive Director of Djerriwarrh Investments Ltd ASX: DJW (since 2010), Equity Trustees Ltd ASX: EQT (since 2007), Victorian Funds Management Corporation, Guild Group, Defence Health and Port of Melbourne Corporation. Ms Williams is also a Council member of the Cancer Council of Victoria. Special Responsibilities Ms Williams is Chairman of the Audit and Risk Committee and a member of the Remuneration and Nomination Committee. Experience and expertise Mr Gordon is a very successful geologist with over 35 years’ 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 Somerton Energy Pty Ltd formerly Somerton Energy Ltd, a listed company until the takeover by Cooper Energy in 2012. He is a former director of ERO Mining Limited (2011-2013). Special Responsibilities As a part time executive of the Company, Mr Gordon is responsible for overseeing exploration and production activities and providing technical expertise in these areas. He is also Chairman of the HSEC Management Committee and the Indonesian Management Committee. Mr Laurence J. Shervington LLB, SA FIN, MAICD Independent Non-Executive Director Appointed 01 October 2003 Former Chairman (November 2004 – February 2013) Resigned 7 November 2013 Experience and expertise Mr Shervington is a respected and experienced corporate lawyer with more than 40 years’ involvement in business and legal landscapes. His corporate expertise includes capital raising, reconstruction, mergers and acquisitions, directors’ duties, corporate governance, due diligence, risk management and ASIC licensing and investigations. Current and other directorships in the last 3 years Mr Shervington is the chair of the Broome Port Authority (since 2011) and a director of the College of Law Western Australia Pty Ltd (since 2008). Mr Shervington is a director of Leedal Pty Ltd, an Aboriginal-directed company with extensive business interests in Fitzroy Crossing in the Kimberley region of Western Australia (since 2008). Special Responsibilities Mr Shervington was a member of the Remuneration and Nomination and Audit and Risk Committees until his resignation as Director. 35 DIRECTORS’ STATUTORY REPORT For the year ended 30 June 2014 2. Company Secretaries 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 held Company Secretary and Legal Counsel roles 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 Jason de Ross was appointed to the position of Company Secretary on 25 November 2013. Mr de Ross has over 20 years’ experience in finance, treasury, strategy and commercial management, mostly in the construction and resources sectors. Prior to joining Cooper Energy as CFO he was employed by OZ Minerals as Group Manager Commercial Operations and was previously Group Commercial Manager and Treasurer with the Futuris/Elders Group. 3. Directors’ Meetings The number of Directors’ meetings (including meetings of committees of Directors) and number of meetings attended by each of the Directors of the parent entity during the financial year are: Director Board Meetings Audit & Risk Committee Meetings Remuneration and Nomination Committee Meetings Mr J.C. Conde Mr D.P. Maxwell Mr J.W. Schneider Mr H.M. Gordon Ms A. Williams1 Mr L.J. Shervington2 A 10 10 10 9 9 4 B 10 10 10 10 9 4 A 2 - 2 - 1 1 B 2 - 2 - 1 1 A 3 - 3 - 2 0 B 3 - 3 - 2 1 A = Number of meetings attended. B = Number of meetings held during the time the Director held office, or was a member of the committee, during the year 1 Appointed 28 August 2013 2 Resigned 7 November 2013 4. Remuneration Report (Audited) This Remuneration Report sets out information about the remuneration of the Company’s key management personnel for the financial year ended 30 June 2014. The information in this Report has been audited as required by the Corporations Act 2001 (Cth) and forms part of the Directors’ Report. 4.1 Key Management Personnel (KMP) The following were KMP of the Group during the reporting period and, unless indicated otherwise, for the whole of the reporting period: Executive Directors Mr D. Maxwell (Managing Director) Mr H. Gordon (Executive Director Production and Exploration) Non-Executive Directors Mr J. Conde AO (Chairman) Mr J. Schneider Ms A. Williams1 Mr L. Shervington2 1 Appointed 28 August 2013 2 Resigned 7 November 2013 36 DIRECTORS’ STATUTORY REPORT For the year ended 30 June 2014 4. Remuneration Report (Audited) continued 4.1 Key Management Personnel (KMP) continued Executives Mr J. de Ross (Chief Financial Officer and Company Secretary)1 Ms A.M. Evans (Company Secretary and Legal Counsel) Mr A. D. Thomas (Exploration Manager) Mr I. MacDougall (Operations Manager) 2 1 Appointed as joint Company Secretary on 25 February 2013 2 Appointed 1 February 2014 4.2 Remuneration Framework The Company seeks to attract and retain highly qualified, skilled and motivated Directors and employees to drive performance of the Company and deliver sustainable total shareholder returns. The Company determines remuneration with a view to ensuring that the level and form of remuneration, for KMP in particular, achieve certain objectives including: • attracting and retaining highly skilled directors and employees who are motivated to pursue and deliver the Company’s strategy and goals; • ensuring that directors and employees receive remuneration that is fair, reasonable and competitive; and • providing incentive to deliver future individual and Company performance. Remuneration for Non-Executive Directors consists only of Directors fees and statutory superannuation, and for employees consists of base salary, statutory superannuation, short term incentives, other short term benefits and long term incentives. Remuneration is determined by reference to market conditions and comparisons (e.g. benchmark reports), and in conjunction with the annual review of the performance of Executive Directors, Executives and other employees of the Company. Performance of the Directors of the Company, including the Managing Director, is evaluated by the Board, who may be assisted by the Remuneration & Nomination Committee. The Managing Director reviews the performance of Executives with the assistance of the Remuneration & Nomination Committee. These evaluations take into account criteria such as the achievement toward the Company’s performance benchmarks and the achievement of individual performance objectives. In addition to the annual review of remuneration, the Board obtained and used independent resource industry remuneration data to determine market remuneration rates for all employees in relation to the oil and gas industry in Australia. 4.3 Remuneration & Nomination Committee The Company’s Remuneration & Nomination Committee (comprised during the reporting period of 3 Non-Executive Directors, a majority 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 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 KMP. 4.4 Nature and amount 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. Remuneration paid to the Non-Executive Directors for the reporting period, and for the previous reporting period, is shown in the table in Section 4.12. The maximum aggregate remuneration pool for Non-Executive Directors, as approved by shareholders at the 2012 Annual General Meeting, is $450,000 per annum. The Board believes that to build on the Company’s exploration and development successes to date and to achieve its strategic goals, it may need to attract and retain further well-credentialed directors. The Board is of the view that the current maximum aggregate remuneration pool will not be sufficient to allow for fair and competitive remuneration of additional appointees. Accordingly, at the 2014 Annual General Meeting, a resolution will be put to shareholders seeking approval to increase the maximum amount by $300,000 to $750,000. The Board believes this amount is commensurate with companies similar to the Company. 37 DIRECTORS’ STATUTORY REPORT For the year ended 30 June 2014 4. Remuneration Report (Audited) continued 4.4 Nature and amount of Non-Executive Director remuneration continued 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 during their term. 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’ & Officers’ indemnity insurance and provide access to Company records. 4.5 Nature and amount of Executive (including Executive Director) remuneration Executive remuneration during the reporting period consisted of: • base salary including statutory superannuation; • short term incentive plan (being performance based cash bonuses); • other short term benefits; and • long term incentive plan (being the award of performance rights under the Company’s employee performance rights plan). Remuneration payable to the Executive Directors, and the Executives, for the reporting period, and for the previous reporting period, is shown in the tables in Sections 4.12 and 4.13 (respectively), and each of the above remuneration components is discussed further below. Base salary and superannuation Executives and Executive Directors are paid base salaries which are competitive in the markets in which the Company operates. Individual base salary is set each year based on job description, competitive salary information sourced by the Company and overall competence in fulfilling the requirements of the particular role. Base salary is paid in cash and is not at risk (other than by termination). The Company pays statutory superannuation contributions on behalf of the Executives and Executive Directors. Short term incentive plan (STIP) Each year the Company issues a scorecard establishing targets or key performance indicators (KPIs) to measure the Company’s short term performance over the financial year. The KPIs focus on the core elements which the Board believes are needed to successfully deliver the Cooper Energy strategy and shareholder returns. Oil and gas reserves and production are at the heart of Cooper Energy’s business and are key KPIs. The Managing Director develops the draft scorecard for review by the Remuneration & Nomination Committee, followed by consideration and approval by the Board. The scorecard is approved by the Board no later than 30 September of each year. For each KPI in the scorecard, a base or threshold performance level is established as well as a target, stretch target and super stretch target performance level: • Base – performance in the previous year. • Target – steady growth, or improvement, against performance in the previous year. • Stretch – doing better than target and consistent with leading peers. • Super stretch – doing better than, or best in class, when compared to peers. Each item in the scorecard is assigned a weighting. In the financial year 2014, the scorecard KPIs and their relative weightings were as follows: STIP Key Performance Indicators Quantitative and Financial Reserves & Exploration Portfolio Production Cost Management Non-Financial Measures Safety and environmental performance Strategy and plan implementation Relationships with investors, partners and the Board % 25 20 10 15 20 10 Average weighted performance of the total scorecard is the sum of the performance assessed for each item multiplied by the weighting for each item. 38 DIRECTORS’ STATUTORY REPORT For the year ended 30 June 2014 4. Remuneration Report (Audited) continued 4.5 Nature and amount of Executive (including Executive Director) remuneration continued STIP payments are calculated as a percentage of base salary (inclusive of superannuation). The maximum STIP payment at the various organisational levels, as a percentage of base salary (inclusive of superannuation), is as follows: • Managing Director – 100% • Executive Director – 75% • Executives – 50% • All other employees – 25% The level of the STIP payment that is “at risk” differs between the Managing Director and other employees (including Executives) and is at the discretion of, and reviewed annually by, the Board: • Managing Director – portion of maximum STIP to be paid is based almost entirely on Company performance as assessed by the Board having close regard to scorecard performance. • Other employees (including Executives) – portion of maximum STIP to be paid is based largely on Company performance however individual performance will also be taken into account. Individual performance ratings are determined in employee performance reviews which are undertaken each year by 31 August. In the event that corporate activity occurs such that the Company is merged or taken over then the scorecard will be re-set at the discretion of the Board. The Board may determine to make STIP payments to Employees in the instance where the change in control event occurs prior to the completion of the relevant performance year, then STIP is prorated in accordance with the portion of the year worked. An employee must have been with the Company for 3 months to qualify for any STIP. If the employee is with the Company for 3 months but less than the full year the STIP is pro-rated according to the period of time the employee has been with the Company. If an employee leaves the Company during a year (other than for retirement or due to redundancy) no STIP is payable. If the employee retires or is made redundant then the STIP is pro-rated in accordance with the portion of the year worked. STIP payments, if any, are made in October. Irrespective of the scorecard outcome, payment of any STIP is entirely at the discretion of the Board. STIP payments made to Executive Directors, and Executives, for the reporting period, and for the previous reporting period, are shown in the tables in Sections 4.12 and 4.13 (respectively). Other short term benefits Other short term benefits include the following fringe benefits: car parking and accommodation benefits to the Managing Director. Long term incentive plan (LTIP) The Company believes that encouraging its employees, including Executives, to become shareholders is the best way of aligning their interests with those of the Company’s shareholders. LTIP awards are made in the form of performance rights which have a vesting timeframe of three years. The number of performance rights that vest will be based on the Company’s performance over the same three years. For each performance right that vests, the employee will receive one share at no cost to the employee. The number of performance rights to be granted annually to each employee is calculated by the following formula: Organisational Level Benchmark × Base Salary ÷ Share Price Where: Organisational Level Benchmark is a percentage of Base Salary, which percentage is intended to reflect the level of involvement of the relevant organisational level in pursuing and achieving the Company’s goals, as follows: Organisational Level Organisational Level Benchmark Managing Director Executive Director Executives Senior Technical Professional, Technical and Administration 120% 95% 70% 50% 30% Base Salary is the employee’s fixed annual remuneration (inclusive of superannuation). Share Price is the 30 ASX trading day volume-weighted average share price (VWAP) of the Company’s shares immediately prior to the commencement date. 39 DIRECTORS’ STATUTORY REPORT For the year ended 30 June 2014 4. Remuneration Report (Audited) continued 4.5 Nature and amount of Executive (including Executive Director) remuneration continued Under the LTIP rules, the total number of performance rights to be issued in each tranche is capped at 2% of the issued capital of the Company at the time of issue. The maximum number of rights that may be granted must not, when aggregated with all other rights on issue, if exercised and shares issued, exceed 5% of the total issued capital of the Company at the time of grant of the rights. The 5% limit does not count unregulated offers, such as offers that do not need disclosure because of section 708 of the Corporation Act (which includes offers to the Managing Director, and senior executives). Performance conditions and vesting period The total number of performance rights issued to each employee will be divided into two tranches and will be tested as follows: • 25% of the rights issued (ATSR Tranche) will be measured against the Company’s absolute total shareholder return (ATSR) over 3 years; and • 75% of the rights issued (RTSR Tranche) will be measured against the Company’s relative total shareholder return (RTSR) over 3 years. ATSR is calculated as a percentage difference between the VWAP of shares during the 30 ASX trading days prior to the start of, and the end of, the relevant testing period. RTSR is the Company’s ATSR measured and ranked against the ATSR’s of a peer group of eight companies selected by the Board before the start of each testing period or as soon as practical thereafter. The peer group companies and the Company will be given a ranking from one to nine (with the company with the highest ATSR being ranked one). ATSR and RTSR are used rather than earnings per share (EPS) because, in the Board’s view, EPS would shift the key focus away from the Company’s long-term business objectives which includes successful exploration. The peer group for the performance rights issued in November 2013 and April 2014 were: Beach Energy Limited; Senex Energy Limited; Drillsearch Energy Limited; Tap Oil Limited; Cue Energy Resources Limited; Central Petroleum Limited, AWE Limited and Icon Energy Limited. Each ATSR Tranche and the RTSR Tranche is divided into 3 equal portions. A portion is tested (25% of portion against ATSR and 75% of portion against RTSR) within each of 12, 24 and 36 months from the commencement date of the rights. The number of rights in each performance period Tranche that is achieved at each testing date will then vest at the end of the three year period, providing the employee remains employed with the Company. A three year vesting period is consistent with the typical time cycle for an exploration program and the Company’s strategic emphasis on exploration and growing its reserves base. Performance rights not achieved in year one can be re-tested in year two, those not achieved in year two can be re-tested in year three and those not achieved at the end of year three will lapse. Achievement of performance rights The number of rights achieved on a testing date is determined as follows: ATSR Tranche – 25% of rights ATSR over performance period % of rights achieved Greater than 25% Equal to 15% Equal to 5% Below 5% 100% 50% 25% Nil Where a result falls between the above benchmarks, rights will be achieved on a pro-rata basis. RTSR Tranche – 75% of rights RTSR over performance period RTSR rank % of rights achieved Greater than 75th percentile Greater than 50th, up to 75th, percentile Equal to 50th percentile Below 50th percentile 1 or 2 3 or 4 5 Below 5 100% Pro rata 50% to 100% 50% Nil 40 DIRECTORS’ STATUTORY REPORT For the year ended 30 June 2014 4. Remuneration Report (Audited) continued 4.5 Nature and amount of Executive (including Executive Director) remuneration continued Vesting The Board may, in its absolute discretion, determine that unvested performance rights vest where: • the employee dies; • a takeover bid is made for the Company; • a Court orders a meeting to be held in relation to a proposed compromise or arrangement for the purposes of or in connection with a scheme for the reconstruction of the Company or its amalgamation with any other company or companies; • the Company passes a resolution for voluntary winding up; • an order is made for the compulsory winding up of the Company; • the employee ceases to be employed by the Company by reason of retirement, redundancy, or total and permanent disability; or • if the employee resigns or is removed for reasons other than performance or misconduct. If no determination is made, or if the Board determines that some or all of an employee’s performance rights do not vest, those performance rights will automatically lapse. The Company intends to make changes to the terms of its employee incentive plan rules. These changes will be put to shareholders at the 2014 Annual General Meeting. Details of the changes will be set out in the Explanatory Memorandum accompanying the Notice of Meeting for the 2014 Annual General Meeting. 4.6 Relationship between remuneration framework and Company performance The Company’s remuneration policy seeks to encourage alignment between the performance of the Company and total shareholder returns, and the remuneration of Executives. Short term and, in particular, long term ‘at risk’ incentives only vest when predetermined Company performance objectives are achieved. Company performance The following table shows the Company’s performance over the reporting period and the previous four financial years: 30 June 2014 30 June 2013 30 June 2012 30 June 2011 30 June 2010 Net Profit/(loss) after tax $’000 21,950 1,318 8,381 (10,349) 1,247 EPS Basic EPS Diluted cents cents Year-end share price $ Shares on issue ’000,000 Market Capitalisation $’000,000 6.7 6.4 0.50 329.2 164.6 0.4 0.4 0.38 329.1 125.1 2.8 2.8 0.45 327.3 147.3 (3.5) (3.5) 0.36 292.6 105.3 0.4 0.4 0.37 292.6 111.2 No dividends were paid during any of the financial years. STIP and LTIP For the reporting period to 30 June 2014, the Company’s performance was measured against Company KPIs which were set out in a scorecard and weighted (as described in Section 4.5 above) and the Company met or exceeded a number of its STIP KPIs but did not meet others: STIP Key Performance Indicators 2014 Financial Year Performance Quantitative and Financial Reserves Exploration Portfolio Production Cost Management Non-Financial Measures Safety and environmental performance Strategy and plan implementation Value realisation Relationships with investors, partners and the Board Below Target Above Super Stretch Above Target Target Target Target Below Target Above Target 41 DIRECTORS’ STATUTORY REPORT For the year ended 30 June 2014 4. Remuneration Report (Audited) continued 4.6 Relationship between remuneration framework and Company performance continued This performance will be assessed by the Board and the score, in conjunction with individual performance reviews, will form the basis of STIP payable in October 2014. As described in Section 4.5 above, the LTIP aligns the rewards received by participants with the longer term performance of the Company including by measuring it against its peers. 4.7 No options No options were issued (or forfeited) during the year. 4.8 Employment contracts Mr David Maxwell – Managing Director Mr Maxwell commenced as Managing Director on 12 October 2011 under a contract of employment. The term of the Managing Director’s contract expires on 10 October 2014. 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. Mr Hector Gordon – Executive Director Exploration and Production Mr Gordon commenced as Executive Director Exploration and Production on 26 June 2012 under a contract of employment. The term of Mr Gordon’s contract expires on 24 June 2015. From 1 March 2014, Mr Gordon’s role has been part-time (0.5 full time equivalent). Mr Gordon continues to provide oversight of the exploration and production business. Mr Gordon or the Company may terminate the contract by providing six months written notice or payment in lieu of notice. The Company may also terminate the contract immediately for cause. Deeds of indemnity The Company also entered into deeds of indemnity, insurance and access with each of the Executive Directors under which the Company will, on the terms set out in the deed, provide an indemnity, maintain an appropriate level of Directors’ & Officers’ indemnity insurance and provide access to Company records. Executives The Company has entered into a contract of employment with each Executive. 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. 4.9 External remuneration advisers During the reporting period, the Remuneration & Nomination Committee engaged Strategic Human Resources Pty Ltd (SHR) to benchmark salaries for all employees, including Executives. This involved the review and application of remuneration data sourced from National Rewards Group Inc. The Board is satisfied that the SHR advice was provided free from undue influence by any KMP to whom the advice related. Fees payable to SHR for services to 30 June 2014 totalled $5,875. Annual membership fees payable to National Rewards Group were $3,727. 4.10 Accounting for performance rights The value of the performance rights is recognised as Share Based Payments in the Company’s statement of comprehensive income and amortised over the vesting period. Performance rights were granted on 6 November 2013 and 28 April 2014. The performance 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 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 ASTR, performance conditions (as described in Section 4.5 above). Performance rights are valued using the closing market price on the date they are granted and no adjustment is made for subsequent movements in share price during any vesting period. No rights of any of the Executives or Executive Directors (as listed in the table below) lapsed, or vested, during the reporting period. 42 DIRECTORS’ STATUTORY REPORT For the year ended 30 June 2014 4. Remuneration Report (Audited) continued 4.10 Accounting for performance rights continued The value of performance rights shown in the tables below are the accounting fair values for grants in the reporting period: Granted during the year No. of rights granted during reporting period Fair value of rights at grant date No. of rights vested during reporting period No. of rights vested to date % of rights vested to date Executive Directors Mr D. Maxwell* Mr H. Gordon* Executives Mr A. Thomas* Mr J. de Ross* Ms A. Evans* Mr I. MacDougall** 1,464,564 850,261 529,616 465,609 235,795 312,033 $456,944 $265,281 $165,240 $145,270 $73,568 $112,332 Nil Nil Nil Nil Nil Nil Nil Nil Nil Nil Nil Nil 0% 0% 0% 0% 0% 0% * The vesting date of the performance rights issued on the 6 November 2013 is 10 October 2016. The fair value of these rights was $0.312. These performance rights expire on 11 October 2016. ** Mr I. MacDougall’s employment commenced on 1 February 2014. The grant of rights was prorated for the period of the year for which he was employed by the Company and the grant date was 28 April 2014. The vesting dated of these performance rights is 10 October 2016 with a fair value of $0.36. These performance rights will expire on 17 March 2017. 4.11 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: Held at 1 July 2013 Granted Forfeited on termination Vested during the year Exercisable Held at 30 June 2014 Executive Directors Mr D. Maxwell 2,965,705 1,464,564 Mr H. Gordon 728,731 850,261 Executives Mr A. Thomas Mr J. de Ross Ms A. Evans Mr I. MacDougall 698,412 399,059 153,782 - 529,616 465,609 235,795 312,033 - - - - - - - - - - - - - - - - - - 4,430,269 1,578,992 1,228,028 864,668 389,577 312,033 43 DIRECTORS’ STATUTORY REPORT For the year ended 30 June 2014 4. Remuneration Report (Audited) continued 4.11 Additional remuneration disclosures continued Held at 1 July 2012 Granted Forfeited on termination Vested during the year Exercisable Held at 30 June 2013 Executive Directors Mr D. Maxwell 1,647,713 1,317,992 Mr H. Gordon Executives Mr A. Thomas Mr J. de Ross Ms A. Evans Mr S. Twartz Mr A. Warton Mr S. Blenkinsop Mr J. Baillie Movement in shares - - - - 732,605 569,021 529,788 454,952 728,731 698,412 399,059 153,782 - - - - - - - - - 732,605 403,104 529,788 322,296 - - - - - - 165,917 - 132,656 - - - - - - - - - 2,965,705 728,731 698,412 399,059 153,782 - - - - 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 2013 Purchases Received on vesting of performance rights Sales Held at 30 June 2014 Directors Mr J. Conde AO Mr L. Shervington Mr D. Maxwell Mr J. Schneider Mr H. Gordon Ms A. Williams Executives Mr J. de Ross Directors Mr J. Conde AO Mr L. Shervington Mr D. Maxwell Mr J. Schneider Mr H. Gordon Executives - 250,000 405,933 1,013,190 300,000 176,608 - - 250,000 - - - 200,000 - - - - - - - - - - - - 250,000 Resigned 1,263,190 300,000 176,608 - 200,000 Held at 1 July 2012 Purchases Received on vesting of performance rights Sales Held at 30 June 2013 - 405,933 935,527 300,000 176,608 - - 77,663 - - - - - - - - - - - - - - - - 405,933 1,013,190 300,000 176,608 Resigned Mr S. Blenkinsop 2,933 44 DIRECTORS’ STATUTORY REPORT For the year ended 30 June 2014 4. Remuneration Report (Audited) continued 4.12 Table of Directors’ remuneration for 2013 and 2014 financial years Benefits Long Term Post Employment Share Based Payment (b) Short Term Salary & Fees STIP Directors $ $ Mr J. Conde AO 2014 146,453 Other Short Term Benefits (a) $ - - 1,942 - - - - - - - - - Long Service Leave Super- annuation LTIP Performance Rights Termination Payments Total % Total in Performance Rights $ - - - - - - - - - - - - $ 13,547 4,403 3,175 9,377 8,290 8,056 $ - - - - - - $ $ - 160,000 - - - - - 53,332 39,442 113,566 97,917 97,570 $ - - - - - - 17,775 442,841 - 1,456,208 30.4% 16,470 294,261 - 1,204,610 24.4% 17,775 135,021 16,470 83,440 6,526 - - - - - - - 665,140 20.3% 677,282 12.3% 78,241 - - - 2013 48,929 2014 34,325 2013 104,189 2014 89,627 2013 89,514 2014 612,225 315,000 68,367 2013 613,529 280,350 - 2014 367,225 139,018 6,101 2013 430,522 146,850 - 2014 70,557 2013 - - - 1,158 - Appointed as Chairman on 25/02/13 Mr L. Shervington Resigned on 07/11/13 Mr J. Schneider Appointed as Non- Executive Director on 12/10/11 Mr D. Maxwell Appointed as Managing Director on 12/10/11 Mr H. Gordon Appointed as Executive Director on 26/06/12 Ms A Williams Appointed as Non- Executive Director on 28/08/13 (a) Other short term benefits include fringe benefits on accommodation, car parking and other benefits. (b) 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 4.10 above and in more detail in Note 23 of the Notes to the Financial Statements. None of the performance rights issued have vested and no payments were made for performance rights during the current financial year. 45 DIRECTORS’ STATUTORY REPORT For the year ended 30 June 2014 4. Remuneration Report (Audited) continued 4.13 Table of Executives’ remuneration for 2013 and 2014 financial years Benefits Short Term Long Term Post Employment Share Based Remuneration(b) Base Salary & Fees STIP Other Short Term Benefits (a) Long Service Leave Super- annuation Performance Rights Termination Payments Total % Total in Performance Rights $ $ $ $ $ $ $ $ $ Directors Mr A. Thomas Commenced as Exploration Manager on 01/07/12 Mr J. de Ross Commenced as Chief Finance Officer on 27/02/12 and as Company Secretary on 25/11/13 Ms A. Evans Commenced as Company Secretary and Legal Counsel (0.6 FT equivalent) on 21/02/12 Mr S. Twartz Made redundant on 31/07/12 Mr J. Baillie Made redundant on 31/12/12 Mr S. Blenkinsop Resigned on 05/07/12 Mr A. Warton Made redundant on 31/12/12 Mr I. MacDougall 2014 372,775 97,638 5,568 2013 341,030 91,341 - 2014 325,575 108,588 5,992 2013 232,897 80,252 - 2014 153,474 43,470 5,992 2013 46,260 11,342 2014 - - 2013 97,845 93,294 2014 - - 2013 187,343 91,412 2014 - 2013 79,364 2014 - - - - 2013 223,357 102,850 - - - - - - - - - 2014 138,664 37,760 1,957 Commenced as Operations Manager 02/02/14 2013 - - - - - - - - - - - - - - - - - - 17,775 114,515 - 608,271 18.8% 16,470 82,386 - 531,227 15.5% 17,775 73,939 - 531,869 13.9% 12,352 45,692 - 371,193 12.3% 14,196 27,069 - 244,201 11.1% 4,163 1,064 - 1,372 - - - - 62,829 1.7% - - - 158,480 350,991 - - - 2,745 - 8,235 6,998 - - - - - - - 82,109 - - (c) 163,995 498,437 6,241 - 191,620 3.3% - - - - - - - - - - - - 36,470 8,235 - (c) 249,385 572,845 (a) Other short term benefits include fringe benefits on accommodation, car parking and other benefits. (b) 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 4.10 above and in more detail in Note 23 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. (c) In the previous financial year performance rights vested on termination of employment. The value of these performance rights issued to John Baillie and Aleksander Warton was $34,623 and $43,304 respectively. 46 DIRECTORS’ STATUTORY REPORT For the year ended 30 June 2014 4. Remuneration Report (Audited) continued 4.14 Realised Remuneration The Company believes that reporting pay ‘actually realised’ (i.e. received) by Executives is useful to shareholders and provides clear and transparent disclosure of remuneration paid by the Company. The following table shows remuneration ‘actually realised’ by the Executives during the reporting period. This information is non-IFRS and unaudited and is in addition to and different from the disclosures required by the Corporations Act and Accounting Standards, which are included in the Remuneration Report on pages 36 to 47 The table below sets out the STIP cash bonus that was actually paid to the Executive during the current reporting period in respect of prior period performance. In contrast, the amounts shown in Table 4.12 and 4.13 above represent an estimate of the bonus that the Executive will receive in the subsequent financial year for their current reporting period performance, along with a true-up for any difference between the amount accrued and the amount paid for the preceding period. As a general principle, the Accounting Standards require a value to be placed on LTIP awards based on probabilistic calculations at the time of grant. This value is not relative to or indicative of the actual benefit (if any) that may ultimately be realised by Executives if the performance hurdles are met and the performance rights vest. The table below sets out the value of the LTIP based on the closing price of the shares issued to the Executive on the date of vesting (if any). Name Year Fixed Remuneration1 STIP2 LTIP 3 Other 4 Total Executive Directors Mr D Maxwell Mr H Gordon Executives Mr A Thomas Mr J de Ross Ms A Evans Mr I MacDougall Mr S Twartz Mr J Baillie Mr S Blenkinsop Mr A Warton 2014 2013 2014 2014 2013 2014 2013 2014 2013 2014 2013 2014 2013 2014 2013 2014 2013 2014 2013 630,000 629,999 385,000 446,992 390,550 357,500 343,350 245,249 167,670 50,423 145,661 - - 280,350 187,348 146,850 - 91,341 - 80,252 22,750 11,342 - - - - 99,217 93,294 - 195,578 - 82,109 - - 91,412 - - - - - - - - - - - - - - - - - - 68,367 - 6,101 - 5,568 - 5,992 - 5,992 - 1,957 - - 978,717 817,347 537,951 446,992 487,459 357,500 429,594 267,999 185,004 50,423 147,618 - - 158,480 350,991 - - 61,022 249,385 597,397 - - - - - - - 82,109 - 231,592 102,850 76,322 163,995 574,759 1. ‘Fixed Remuneration’ comprises base salary and superannuation. 2. ‘STIP’ is the amount of the STIP cash bonus that was actually paid to the executive during the 2014 financial year in respect of performance in the 2013 financial year. For the value of the STIP calculated in accordance with the Accounting Standards, see the tables in section 4.12 on page 45 and section 4.13 on page 46. 3. The figures in this ‘LTIP’ column show the pre-tax vested value of performance rights which vested during the reporting period, calculated based on the share price on the date the performance rights were vested. 4. ‘Other’ short term benefits include fringe benefits on accommodation, car parking and other benefits. End of remuneration report. 47 DIRECTORS’ STATUTORY REPORT For the year ended 30 June 2014 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 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. 9. Likely Developments Other than disclosed elsewhere in the Financial Report, 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 J. Schneider Mr H. Gordon Ms A. Williams Cooper Energy Limited Ordinary Shares Performance Rights 250,000 1,263,190 300,000 176,608 - - 4,430,269 - 1,578,992 - 11. Share Options And Performance 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 have been 14,748,003 performance rights granted to employees under the Employee Performance Rights Plan. 12. Events After Financial Reporting Date Refer to Note 26 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. 48 DIRECTORS’ STATUTORY REPORT For the year ended 30 June 2014 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 97 and forms part of the Directors’ report for the financial year ended 30 June 2014. 17. Non-Audit Services The amounts paid to the auditor of the Group, Ernst & Young and its related practices for non-audit services provided during the year was $nil (2013: $nil). 18. Rounding The Group is of a kind referred to in ASIC Class Order 98/0100 dated 10 July 1998 and in accordance with that Class Order, 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 18 August 2014 49 50 FINANCIAL STATEMENTS For the year ended 30 June 2014 5151 CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME For the year ended 30 June 2014 Continuing Operations Revenue from oil sales Cost of sales Gross profit Other revenue Exploration and evaluation expenditure written off Finance costs Impairment of available for sale financial assets Administration and other expenses Profit before tax Taxes Income tax expense Petroleum Resource Rent Tax Total tax expense Consolidated 2014 $000 2013 $000 Notes 4 4 4 4 4 5 5 5 72,303 53,397 (26,056) (23,541) 46,247 29,856 2,842 (1,261) (296) (3,064) 2,343 (1,493) (39) - (13,258) (12,364) 31,210 18,303 (9,028) (5,569) - (11,019) (9,028) (16,588) Net profit after tax from continuing operations 22,182 1,715 Discontinued operations Impairment of exploration assets held for sale after income tax Total profit for the period attributable to members Other comprehensive income/(expenditure) Items that may be reclassified subsequently to profit or loss Foreign currency translation reserve Fair value movements on available for sale investments Income tax effect on fair value movements Reclassification during the year to profit or loss of impairment on AFS investments Other comprehensive income/(expenditure) for the period net of tax 10 (232) 21,950 (397) 1,318 (164) 5,796 (1,346) 3,064 7,350 - (2,377) - - (2,377) Total comprehensive income/(loss) for the period attributable to members 29,300 (1,059) Basic earnings per share from continuing operations Diluted earnings per share from continuing operations Basic earnings per share Diluted earnings per share cents cents 6 6 6 6 6.7 6.5 6.7 6.4 0.5 0.5 0.4 0.4 The above Statement of Comprehensive Income should be read in conjunction with the accompanying notes. 52 CONSOLIDATED STATEMENT OF FINANCIAL POSITION As at 30 June 2014 Consolidated 2014 $000 2013 $000 Notes Assets Current Assets Cash and cash equivalents Trade and other receivables Inventory Prepayments Exploration assets classified as held for sale Total Current Assets Non-Current Assets Available for sale financial assets Other non-current receivables Term deposits at banks Oil properties Other property, plant & equipment Exploration and evaluation Total Non-Current Assets Total Assets Liabilities Current Liabilities Trade and other payables Income tax payable Exploration liabilities classified as held for sale Total Current Liabilities Non-Current Liabilities Deferred tax liabilities Provisions Financial liabilities Total Non-Current Liabilities Total Liabilities Net Assets Equity Contributed equity Reserves Retained profits Total Equity 7 8 9 10 11 7 12 13 14 15 5 10 5 16 17 18 18 18 The above Statement of Financial Position should be read in conjunction with the accompanying notes 47,178 10,901 289 732 59,100 46,906 106,006 43,154 19,457 204 757 63,572 23,809 87,381 26,040 20,182 244 1,919 18,293 1,141 94,621 142,258 - 4,766 17,416 1,464 30,846 74,674 248,264 162,055 12,896 5,040 17,936 2,740 20,676 14,431 41,360 4,004 59,795 11,845 - 11,845 573 12,418 9,102 3,325 - 12,427 80,471 24,845 167,793 137,210 114,625 114,570 7,440 45,728 (1,138) 23,778 167,793 137,210 53 CONSOLIDATED STATEMENT OF CHANGES IN EQUITY For the year ended 30 June 2014 Balance at 1 July 2013 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 Shares issued Balance at 30 June 2014 Issued Capital $’000 Reserves Retained Earnings Total Equity $’000 $’000 $’000 114,570 (1,138) - - - - 55 - - 7,350 7,350 1,283 (55) - 23,778 21,950 - 21,950 137,210 21,950 7,350 29,300 - - - 1,283 - - 114,625 7,440 45,728 167,793 Balance at 1 July 2012 Profit for the period Other comprehensive (expenditure) Total comprehensive income/(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 2013 113,877 - - - - 106 587 608 - (2,377) (2,377) 737 (106) - 22,460 136,945 1,318 - 1,318 1,318 (2,377) (1,059) - - - 737 - 587 114,570 (1,138) 23,778 137,210 The above Statement of Changes in Equity should be read in conjunction with the accompanying notes 54 CONSOLIDATED STATEMENT OF CASH FLOWS For the year ended 30 June 2014 Cash Flows from Operating Activities Receipts from customers Payments to suppliers and employees Income tax received/(paid) Interest received – other entities Net cash from operating activities Cash Flows from Investing Activities Transfers of/(Placements on) term deposits Payment for available for sale financial assets Receipts from sale of other property, plant & equipment Receipts from sale of financial assets Payments for exploration and evaluation Investments in oil properties Net cash flows used in investing activities Cash Flows from Financing Activities Payment for shares Net cash flow used in 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 The above Statement of Cash Flows should be read in conjunction with the accompanying notes Consolidated 2014 $000 2013 $000 Notes 80,991 45,197 (32,431) (31,491) 300 1,398 7 50,258 (3,413) 2,161 12,454 2,847 (2,315) 11 (62) (10,172) 12 - - 1,161 (43,333) (10,978) (5,967) (6,201) (46,503) (28,505) (55) (55) (85) (85) 3,700 324 43,154 47,178 (16,136) 280 59,010 43,154 7 55 1. Corporate Information The consolidated financial report of Cooper Energy Limited (the parent entity) for the year ended 30 June 2014 was authorised for issue in accordance with a resolution of the Directors on 15 August 2014. Cooper Energy Limited is a company limited by shares incorporated and domiciled in Australia whose shares are publicly traded on the Australian Securities Exchange. The nature of the operations and principal activities of the Group are described in note 5 of the Directors Report. 2. Summary of Significant Accounting Policies a) Basis of preparation The financial report is a general-purpose financial report, which has been prepared in accordance with the requirements of the Corporations Act 2001 and Australian Accounting Standards and other authoritative pronouncements of the Australian Accounting Standards Board. The financial report has also been prepared on a historical cost basis, except for available for sale financial assets which have been measured at fair value. Cooper Energy Limited is a for profit company. The financial report is presented in Australian dollars and all values are rounded to the nearest thousand dollars ($’000) unless otherwise stated under the option available to the Group under ASIC Class Order 98/0100. The Group is an entity to which the class order applies. Significant event and transaction On 31 March 2014 Cooper Energy Ltd announced the acquisition of a 65% interest in the Basker/Manta/Gummy gas and liquids project (BMG). The acquisition was completed in May 2014. This acquisition consisted of 3 production licences with undeveloped resources and Cooper Energy assumed any abandonment liability for the interests purchased at 39% until October 2018 and then 65% thereafter. For cash costs of $1.877million, Cooper Energy made an asset acquisition consisting of the following: • BMG Exploration assets acquired $42.443 million • Abandonment provisions $36.601 million • Success Fee Liability $3.965 million Change in functional currency Refer to Note 2 f) for further detail. b) Statement of compliance (i) Changes in accounting policy and disclosures. The financial report complies with Australian Accounting Standards and International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board. The Accounting policies adopted are consistent with those of the previous financial year except as follows: The Group has adopted the following new and amended Australian Accounting Standard and AASB Interpretations as of 1 July 2013: • AASB 10 Consolidated Financial Statements • AASB 11 Joint Arrangements • AASB 12 Disclosure of Interests in Other Entities • AASB 13 Fair Value Measurement • AASB 119 Employee Benefits • AASB 2012-2 Amendments to Australian Accounting Standards – Disclosures – Offsetting Financial Assets and Financial Liabilities • AASB 2011-4 Amendments to Australian Accounting Standards to Remove Individual Key Management Personnel Disclosure Requirements (AASB 124) 56 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 20142. Summary of Significant Accounting Policies continued b) Statement of compliance continued Adoption of these standard interpretations is described below: AASB 10 Summary Consolidated Financial Statement AASB 10 establishes a new control model that applies to all entities. It replaces parts of AASB 127 Consolidated and Separate Financial Statements dealing with the accounting for consolidated financial statement and UIG -112 Consolidation – Special Purpose Entities. The new control model broadens the situations when an entity is considered to be controlled by another entity and includes new guidance for applying the model to specific situations, including when acting as a manager may give control, the impact of potential voting rights and when holding less than a majority voting rights may give control. Consequential amendments were also made to this and other standards via AASB 2011-7, and AASB 2012-10. Application Date of the Standard 1 January 2013 Application date for Group 1 July 2013 Impact on Group financial report The Group’s existing recognition of control did not change with the adoption of this accounting standard. AASB 11 Joint Arrangements AASB 11 replaces AASB 131 Interests in Joint Ventures and UIG-113 Jointly-controlled Entities – Non-monetary Contributions by Ventures. AASB 11 uses the principle of control in AASB 10 to define joint control and therefore the determination of whether joint control exists may change. In addition it removes the option to account for jointly controlled entities (JCEs) using proportionate consolidation. Instead, accounting for a joint arrangement is dependent on the nature of the rights and obligations arising from the arrangement. Joint operations that give the venturers a right to the underlying assets and obligations themselves is accounted for by recognising the share of those assets and obligations. Joint ventures that give the venturers a right to the net assets is accounted for using the equity method. Consequential amendments were also made to this and other standards via AASB 2011-7, AASB 2010-10 and amendments to AASB 128. Amendments made by the IASB in May 2014 add guidance on how to account for the acquisition of an interest in a joint operation that constitutes a business. Application Date of the Standard 1 January 2013 Application Date for Group 1 July 2013 Impact on Group Financial report The Group has several joint arrangements currently in place. The joint arrangements are considered to be joint operations under the new standard. As such the group recognises its’ interest in the joint venture for assets, liabilities, revenues from sale of output and expenses incurred. There was no impact from the application of this standard as the treatment is consistent with the Group’s previous practice. AASB 12 Summary Disclosure of Interests in Other entities AASB 12 includes all disclosures relating to an entity’s interests in subsidiaries, joint arrangements, associates and structured entities. New disclosures have been introduced about the judgements made by management to determine whether control exists, and to require summarised information about joint arrangements, associates, structured entities and subsidiaries with non-controlling interests. Application Date of the Standard 1 January 2013 Application Date for Group 1 July 2013 Impact on Group Financial report The Group has provided more extensive and detailed disclosures in relation to its subsidiaries and joint arrangements. These disclosures will enable users of the Group’s consolidated financial statements to further evaluate any restrictions on the ability of the Group to use assets, the nature and change of any risks. These disclosures do not have a financial impact upon the financial statements. 57 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 20142. Summary of Significant Accounting Policies continued b) Statement of compliance continued AASB 13 Summary Fair Value Measurement AASB 13 establishes a single source of guidance for determining the fair value of assets and liabilities. AASB 13 does not change when an entity is required to use fair value, but rather, provides guidance on how to determine fair value when fair value is required or permitted. Application of this definition may result in different fair values being determined for the relevant assets. AASB 13 also expands the disclosure requirements for all assets or liabilities carried at fair value. This includes information about the assumptions made and the qualitative impact of those assumptions on the fair value determined. Consequential amendments were also made to other standards via AASB 2011-8. Application Date of the Standard 1 January 2013 Application Date for Group 1 July 2013 Impact on Group Financial report The Group currently utilises fair value measures which are dependent upon the relevant asset. Application of AASB 13 has not materially impacted the fair value measurements of the Group. Additional disclosure around the assumptions made and the qualitative information used in generation of the fair value can be found in Note 19. AASB 119 Summary Employee Benefits The revised standard changes the definition of short-term employee benefits. The distinction between short-term and other long-term employee benefits is now based on whether the benefits are expected to be settled wholly within 12 months after the reporting date. Consequential amendments were also made to other standards via AASB 2011-10. Application Date of the Standard 1 January 2013 Application Date for Group 1 July 2013 Impact on Group Financial report The application of this standard has not resulted in any significant change in the 2014 financial year end accounts. AASB 2012-2 Summary Amendments to Australian Accounting Standards – Disclosures – Offsetting Financial Assets and Financial Liabilities This amendment principally amends AASB 7 Financial Instruments: Disclosures to require disclosure of the effect or potential effect of netting arrangements, including rights of set-off associated with the entity’s recognised financial assets and recognised financial liabilities, on the entity’s financial position, when all the offsetting criteria of AASB 132 are not met. Application Date of the Standard 1 January 2013 Application Date for Group 1 July 2013 Impact on Group Financial report Currently the Group does not offset any financial assets against financial liabilities. No further disclosures have been made. AASB 2011-4 Summary Amendments to Australian Accounting Standards to Remove Individual Key Management Personnel Disclosure Requirements (AASB 124) This amendment deletes from AASB 124 individual key management personnel disclosure requirements for disclosing entities that are not companies. It also removes the individual KMP disclosure requirements for all disclosing entities in relation to equity holdings, loans and other related party transactions. Application Date of the Standard 1 July 2013 Application Date for Group 1 July 2013 Impact on Group Financial report The Group has removed the KMP disclosures for equity holdings and other related party transactions from Note 22. 58 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 2014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 and for which the Group has elected not to early adopt for the annual reporting period ending 30 June 2014, are outlined below: AASB 2012-3 Summary Amendments to Australian Accounting Standards - Offsetting Financial Assets and Financial Liabilities AASB 2012-3 adds application guidance to AASB 132 Financial Instruments: Presentation to address inconsistencies identified in applying some of the offsetting criteria of AASB 132, including clarifying the meaning of "currently has a legally enforceable right of set-off" and that some gross settlement systems may be considered equivalent to net settlement. Application Date of the Standard 1 January 2014 Application Date for Group 1 July 2014 Impact on Group Financial report No change is expected from the adoption of this standard. AASB 1031 Summary Materiality The revised AASB 1031 is an interim standard that cross-references to other Standards and the Framework (issued December 2013) that contain guidance on materiality. AASB 1031 will be withdrawn when references to AASB 1031 in all Standards and Interpretations have been removed Application Date of the Standard 1 January 2014 Application Date for Group 1 July 2014 Impact on Group Financial report No change to the Group is expected from the adoption of this standard. IFRS Annual Improvements 2010-2012 Cycle Summary Annual Improvements to IFRSs 2010–2012 Cycle AASB 2014-1 Part A: This standard sets out amendments to Australian Accounting Standards arising from the issuance by the International Accounting Standards Board (IASB) of International Financial Reporting Standards (IFRSs) Annual Improvements to IFRSs 2010–2012 Cycle and Annual Improvements to IFRSs 2011–2013 Cycle. Annual Improvements to IFRSs 2010–2012 Cycle addresses the following items: • AASB 2 - Clarifies the definition of ‘vesting conditions’ and ‘market condition’ and introduces the definition of ‘performance condition’ and ‘service condition’. • AASB 3 - Clarifies the classification requirements for contingent consideration in a business combination by removing all references to AASB 137. • AASB 8 - Requires entities to disclose factors used to identify the entity’s reportable segments when operating segments have been aggregated. An entity is also required to provide a reconciliation of total reportable segments’ asset to the entity’s total assets. • AASB 116 & AASB 138 - Clarifies that the determination of accumulated depreciation does not depend on the selection of the valuation technique and that it is calculated as the difference between the gross and net carrying amounts. • AASB 124 - Defines a management entity providing KMP services as a related party of the reporting entity. The amendments added an exemption from the detailed disclosure requirements in paragraph 17 of AASB 124 for KMP services provided by a management entity. Payments made to a management entity in respect of KMP services should be separately disclosed. Application Date of the Standard 1 July 2014 Application Date for Group 1 July 2014 Impact on Group Financial report Adoption of this standard will have no impact upon the Group financial statements or the related disclosures. 59 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 20142. Summary of Significant Accounting Policies continued b) Statement of compliance continued Amendments to IAS 16 and IAS 38 Clarification of Acceptable Methods of Depreciation and Amortisation (Amendments to IAS 16 and IAS 38) Summary IAS 16 and IAS 38 both establish the principle for the basis of depreciation and amortisation as being the expected pattern of consumption of the future economic benefits of an asset. The IASB has clarified that the use of revenue-based methods to calculate the depreciation of an asset is not appropriate because revenue generated by an activity that includes the use of an asset generally reflects factors other than the consumption of the economic benefits embodied in the asset. The IASB also clarified that revenue is generally presumed to be an inappropriate basis for measuring the consumption of the economic benefits embodied in an intangible asset. This presumption, however, can be rebutted in certain limited circumstances. Application Date of the Standard 1 January 2016 Application Date for Group 1 July 2016 Impact on Group Financial report The Group currently uses diminishing value and units of production bases for the calculation of depreciation and amortisation. This standard will have no impact upon the Group’s current methodologies. IFRS 15 Summary Revenue from Contracts with Customers In May 2014, the IASB issued IFRS 15 Revenue from Contracts with Customers, which replaces IAS 11 Construction Contracts, IAS 18 Revenue and related Interpretations (IFRIC 13 Customer Loyalty Programmes, IFRIC 15 Agreements for the Construction of Real Estate, IFRIC 18 Transfers of Assets from Customers and SIC-31 Revenue—Barter Transactions Involving Advertising Services). The core principle of IFRS 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. 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 in the current format is not expected to have a material impact on the Group. 60 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 20142. Summary of Significant Accounting Policies continued b) Statement of compliance continued AASB 9 Summary Financial Instruments On 24 July 2014 The IASB issued the final version of IFRS 9 which replaces IAS 39 and includes a logical model for classification and measurement, a single, forward-looking ‘expected loss’ impairment model and a substantially-reformed approach to hedge accounting. IFRS 9 is effective for annual periods beginning on or after 1 January 2018. However, the Standard is available for early application. The own credit changes can be early applied in isolation without otherwise changing the accounting for financial instruments. The final version of IFRS 9 introduces a new expected-loss impairment model that will require more timely recognition of expected credit losses. Specifically, the new Standard requires entities to account for expected credit losses from when financial instruments are first recognised and to recognise full lifetime expected losses on a timely basis. The AASB is yet to issue the final version of AASB 9. A revised version of AASB 9 (AASB 2013-9) was issued in December 2013 which included the new hedge accounting requirements, including changes to hedge effectiveness testing, treatment of hedging costs, risk components that can be hedged and disclosures. AASB 9 includes requirements for a simplified approach for classification and measurement of financial assets compared with the requirements of AASB 139. The main changes are described below. (a) Financial assets that are debt instruments will be classified based on (1) the objective of the entity’s business model for managing the financial assets; (2) the characteristics of the contractual cash flows. (b) Allows an irrevocable election on initial recognition to present gains and losses on investments in equity instruments that are not held for trading in other comprehensive income. Dividends in respect of these investments that are a return on investment can be recognised in profit or loss and there is no impairment or recycling on disposal of the instrument. (c) Financial assets can be designated and measured at fair value through profit or loss at initial recognition if doing so eliminates or significantly reduces a measurement or recognition inconsistency that would arise from measuring assets or liabilities, or recognising the gains and losses on them, on different bases. (d) Where the fair value option is used for financial liabilities the change in fair value is to be accounted for as follows: • The change attributable to changes in credit risk are presented in other comprehensive income (OCI) • The remaining change is presented in profit or loss AASB 9 also removes the volatility in profit or loss that was caused by changes in the credit risk of liabilities elected to be measured at fair value. This change in accounting means that gains caused by the deterioration of an entity’s own credit risk on such liabilities are no longer recognised in profit or loss. Consequential amendments were also made to other standards as a result of AASB 9, introduced by AASB 2009-11 and superseded by AASB 2010-7, AASB 2010-10 and AASB 2014-1 – Part E. Application Date of the Standard 1 January 2018 Application Date for Group 1 July 2018 Impact on Group Financial report The Group will quantify the effect in conjunction with the other phases, when the final standard including all phases is issued. The Group has not early adopted any other standard, interpretation or amendment that has been issued but is not yet effective. 61 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 20142. Summary of Significant Accounting Policies continued 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 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 139 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 139, 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 whether other assets or liabilities of the acquirer are assigned to those units. 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. e) Joint arrangements The Group has an interest 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 • Share of the revenue from the sale of the output by 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 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. 62 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 20142. Summary of Significant Accounting Policies continued f) Foreign currency continued During the period, the Group performed a reassessment of the economic environment in which Cooper Energy Sukananti Ltd operates, and as a result, the entity’s functional currency was changed from Australian dollars to US dollars. This is primarily due to the fact that during the period the entity has been cash flow positive and therefore is no longer expected to be totally reliant on Cooper Energy for funding. The change in functional currency has been applied prospectively with effect from 1 July 2013, in accordance with the requirements of the Australian Accounting Standards. The exchange rate at 1 July 2013 was 0.9275. The assets and liabilities of this entity are translated into the presentation currency of the Group at the rate of exchange ruling at the respective reporting date. The income statements are translated at the average exchange rates for the reporting period, or at the exchange rates ruling at the date of transactions. Exchange differences arising on translation of Australian dollar denominated intercompany loans are taken to the foreign currency translation reserve in equity. The total impact to foreign currency translations reserve for the current year is an unrealised loss of $164,000. The remaining foreign operations of the group have an Australian dollar functional currency. g) Investments Investments are classified as available-for-sale 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. Designation will be re-evaluated at each financial year-end. After initial recognition, investments are remeasured to fair value. Changes in the fair value of available-for-sale investments are recognised as a separate component of equity until the investment is sold, collected or otherwise disposed of, or until the investment is determined to be impaired when there is a significant or prolonged decline in the fair value, at which time the cumulative change in fair value previously reported in equity is included in earnings. 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. 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 method, 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. i) Depreciation and amortisation Oil properties and other plant and equipment, other than freehold land, are depreciated to their residual values at rates based on the expected useful lives of the assets concerned. Oil properties are amortised on the Units of Production basis using the best estimate of proved and probable (2P) reserves. 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, annual leave and accumulating sick leave. Liabilities to be settled within twelve months of the reporting date 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 on national government 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 in section 4 of the Directors’ Report. 63 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 20142. Summary of Significant Accounting Policies continued 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, 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 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 is reflected as additional share dilution in the computation of diluted earnings per share. 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) Joint Venture fees Revenue is recognised when the Group’s right to receive payment is established or services are rendered. n) 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. 64 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 20142. Summary of Significant Accounting Policies continued n) Income tax continued 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 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. 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. 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. o) 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. 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. The Group has lodged starting base returns for all exploration and production areas. In June 2013, participants including the Company were granted a combination certificate for the Cooper Basin projects essentially deeming PEL 92 and PEL 93 to be a single project for PRRT purposes. 65 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 20142. Summary of Significant Accounting Policies continued p) Exploration and evaluation expenditure Exploration and evaluation expenditure is accounted for in accordance with the area of interest method and is capitalised to the extent that: i. ii. 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 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 properties. q) Oil properties Oil properties are carried at cost including construction, installation of infrastructure such as roads 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. r) 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 after the construction of the facility and then reviewed on an annual basis. When the liability is recorded the carrying amount of the production assets is increased by the asset retirement costs and 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 asset and then depreciated over the producing life of the asset. 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. s) 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. 66 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 20142. Summary of Significant Accounting Policies continued s) Property, plant and equipment continued The assets’ residual values and useful lives are reviewed, and adjusted if appropriate, at each Consolidated Statement of Financial Position date. The carrying values of property, plant and equipment 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 property, plant and equipment is the higher of fair value less cost to sell and value in use. For an asset that does not generate largely independent cash flows, recoverable amount is determined for the cash generating unit to which the asset belongs, unless the asset’s value in use can be estimated to be close to its fair value. An asset’s or cash generating unit’s carrying amount is written down immediately to its recoverable amount if the asset’s or cash generating unit’s carrying amount is greater than its estimated recoverable amount. 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. t) Impairment of non-current assets Assets that are subject to amortisation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the asset’s carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset’s fair value less costs to sell and value in use. 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. u) Cash and cash equivalents Cash and short term deposits in the Consolidated Statement of Financial Position comprise cash at bank and short term deposits with an original maturity of twelve months or less. For the purposes of the Statement of Cash Flows, cash 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. v) 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 when there is objective evidence that the Group will not be able to collect the debts. Financial difficulties of the debtor, default payments or debts more than 90 days overdue are considered objective evidence of impairment. The amount of the impairment loss is the receivable carrying amount, compared to the present value of estimated future cash flows, discounted at the original effective interest rate. Bad debts are written off when identified. 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. 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 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. 67 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 20142. Summary of Significant Accounting Policies continued aa) 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. 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 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. 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 a commercial property lease. The Group has determined that is does not retain any of the significant risks and rewards of ownership of this property and has thus classified the lease as an operating lease. (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. Recoverability of trade and other receivables The future recoverability of part of trade receivables from the sale of hydrocarbons is dependent on the average spot price for oil and the currency exchange rate for the Australian dollar to the United States dollar at the date of export from Australia. 68 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 20142. Summary of Significant Accounting Policies continued (ii) Significant accounting estimates and assumptions continued Factors that could impact on the future recoverability of the trade receivables are the movement in the daily spot Australian dollar to the United States dollar and the spot price for crude oil which are both publically quoted prices. 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. Factors which could impact the future recoverability include the level of oil reserves, future technological changes which could impact the cost of extraction, future legal changes (including changes to environmental restoration obligations) and changes to commodity prices. 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 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 of oil properties and property, plant & equipment The Group reviews the carrying amount of oil properties 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 makes assumptions regarding future production and sales volumes, pricing, foreign exchange rates and capital and operating expenditure. 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 and pricing. Provisions for decommissioning and restoration costs Decommissioning and restoration costs are a normal consequence of oil 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 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 The Group operates throughout the world and prepares reports internally and externally by continental geographical segments. Within each segment, the costs of operations and income are prepared firstly by legal entity and then by joint venture. Revenue and outgoings are allocated by way of their natural expense and income category. These reports are drawn up on a quarterly basis. Resources are allocated between each segment on an as needs basis. Selective reporting is provided to the Board quarterly while the annual and bi- annual results are reported to the Board. The Managing Director is the chief operating decision maker. Other prospective opportunities outside of these geographical segments are also considered from time to time and, if they are secured, will then be attributed to the continental geographical segment where they are located. The current external customers by geographical location of production are the Australian Business Unit with two customers and the Indonesian Business Unit with one customer. The following are the current geographical segments: Australian Business Unit Exploration and evaluation for oil and gas, development, production and sale of crude oil in a number of areas in the Cooper Basin located in South Australia. 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. Interest income is earned from the placement of funds with various Australian Banks for periods of up to six months. 69 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 20143. Segment reporting continued Asian Business Unit The Asian business unit involved the production and sale of crude oil from the Tangai-Sukananti KSO. It is located on the island of Sumatra, Indonesia. Revenue is derived from the sale of crude oil to PT Pertamina EP. The Group is also involved in exploration and evaluation for oil and gas in the Sumbagsel and Merangin III Permit areas on the island of Sumatra, Indonesia. African Business Unit Exploration and evaluation for oil and gas in the Bargou, Nabeul and Hammamet permit areas off the coast of Tunisia. No income is derived from these units. The Company has announced its intention to dispose of the equity interests in the Tunisian assets. European Business Unit The Company has disposed of all exploration interests in Poland and is in the process of winding up the Polish and Dutch subsidiaries. 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. Geographical Segments Australian Business Unit African Business Unit (disc. operation) Asian Business Unit European Business Unit (disc. operation) Elimination Consolidated $’000 $’000 $’000 $’000 $’000 $’000 Year ended 30 June 2014 Revenue Interest and other revenue Total consolidated revenue Depreciation of property Amortisation of: - Development costs - Exploration costs Finance costs Share based payments Exploration costs written off Segment result Income tax Net Profit Segment liabilities Segment assets Non-Current Assets Cash flow from: 66,457 3,973 70,430 (434) (4,943) (1,112) (296) (1,283) (1,261) 30,396 - - - - - - - - - 5,846 - 5,846 (52) (707) - - - - - - - - - - - - - - (1,131) (1,131) - - - - - - (17) 2,177 (215) (1,131) 75,767 185,825 129,555 2,670 46,844 - 1,963 15,533 12,703 1,360 (4,645) - 71 62 - 110 (180) - (180) - - - - - - - - Operating activities 48,100 688 - Investing activities (19,529) (22,149) - Financing (55) - Capital Expenditure (22,351) (22,149) (4,620) 70 72,303 2,842 75,145 (486) (5,650) (1,112) (296) (1,283) (1,261) 31,210 (9,028) 22,182 80,471 248,264 142,258 50,258 (46,503) (55) (49,300) NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 2014 3. Segment reporting continued Geographical Segments Australian Business Unit African Business Unit (disc. operation) Asian Business Unit European Business Unit (disc. operation) Elimination Consolidated $’000 $’000 $’000 $’000 $’000 $’000 Year ended 30 June 2013 Revenue Other revenue Total consolidated revenue Depreciation of property Amortisation of: - Development costs - Exploration costs Finance costs Share based payments Exploration costs written off Segment result Income tax Net Profit 50,977 2,343 53,320 (232) (4,425) (1,513) (39) (737) (1,493) 18,861 - - - - - - - - - - 2,420 - 2,420 (60) (150) - - - - - - - - - - - - - (161) (397) Segment liabilities 23,630 574 Segment assets 130,638 23,613 Non-Current Assets 68,538 - Cash flow from: - Operating activities - Investing activities - Financing 16,336 (23,552) (85) (2,053) (832) - 641 7,608 6,136 (1,632) (3,724) - Capital Expenditure (12,255) (832) (3,724) - 196 - (197) (397) - (397) Revenue from external customers by geographical location of production Australia Indonesia Total revenue Revenue from one customer amounted to $63,983,000 (2013:$50,903,000) arising from oil sales. - - - - - - - - - - - - - - - - - 53,397 2,343 55,740 (292) (4,575) (1,513) (39) (737) (1,493) 18,303 (16,588) 1,715 24,845 162,055 74,674 12,454 (28,505) (85) (17,208) 2014 $’000 2013 $’000 66,457 50,977 5,846 2,420 72,303 53,397 71 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 2014 4. Revenues and Expenses Profit before income tax expense includes the following revenues and expenses whose disclosure is relevant in explaining the performance of the entity: Revenues from oil operations Oil sales Total revenue from oil sales Other revenue Interest revenue Other income Joint venture fees Total other revenue Cost of sales Production expenses Royalties Amortisation of exploration costs in areas under production Amortisation of development costs in areas of production Total cost of sales Finance costs Finance cost – accretion of rehabilitation cost Other finance cost Total finance costs Administration and other expenses Depreciation of property, plant and equipment General administration (includes employee benefits and lease payments) Realised and unrealised foreign currency translation loss Total other expenses Employee benefits expense Director and employee benefits Share based payments Lease payments Minimum lease payment – operating lease 72 Consolidated 2014 $’000 2013 $’000 72,303 72,303 53,397 53,397 1,360 1,960 - 1,482 2,842 346 37 2,343 (12,814) (12,357) (6,480) (5,096) (1,112) (1,513) (5,650) (4,575) (26,056) (23,541) (257) (39) (296) (39) - (39) (486) (292) (12,423) (11,961) (349) (111) (13,258) (12,364) (5,716) (6,612) (1,283) (737) (6,999) (7,349) (99) (828) NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 20145. Income Tax The major components of income tax expense are: Consolidated Statement of Comprehensive Income Current income tax Current income tax charge Adjustments in respect of prior year income tax Deferred income tax Origination and reversal of temporary differences Income tax expense Petroleum Resource Rent Tax - deferred tax Total tax expenses Numerical reconciliation between tax expense and pre-tax net profit Accounting profit before tax from continuing operations Income tax using the domestic corporation tax rate of 30% (2013: 30%) Increase/(decrease) in income tax expense due to: Non-deductible expenditure Recognition of previously unrecognised capital losses Adjustments in respect to current income tax of previous years Non Australian taxation jurisdictional subsidiaries Income tax expense Income tax recognised in other comprehensive income Revaluation of available for sale financial assets Income tax using the domestic corporation tax rate of 30% (2013: 30%) Consolidated 2014 $’000 2013 $’000 (5,040) 290 (4,750) - 297 297 (4,278) (5,866) (4,278) (5,866) (9,028) (5,569) - (11,019) (9,028) (16,588) 31,210 18,303 (9,363) (5,491) (1,411) 1,346 290 110 335 (556) 104 297 77 (78) (9,028) (5,569) (1,346) (1,346) - - 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 intercompany 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. Unrecognised temporary differences At 30 June 2014, 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 (2013 $nil). Franking Tax Credits At 30 June 2014 the parent entity had franking tax credits of $38,663,576 (2013: $38,963,577). The fully franked dividend equivalent is $90,215,011 (2013: $90,915,013) 73 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 20145. Income Tax continued PRRT Cooper Energy Limited has not recognised a Deferred Tax Asset for the Petroleum Rent Resource Tax of $19,071,000 (2013: $23,936,000) on the basis that it has a significant level of undeducted expenditure and nil PRRT payments projected in the future. Income Tax Losses (a) Revenue Losses Cooper Energy Limited has not recognised a Deferred Tax Asset for the year ended 30 June 2014 (2013: $3,530,550). All prior recognised Deferred Tax Assets have been fully utilised during the current year. (b) Capital Losses Cooper Energy Limited has recognized a Deferred Tax Asset for $1,346,000 against an unrealized gain on available for sale financial assets. This Deferred Tax Asset is in turn, offset by a Deferred Tax Liability which is recognized in other comprehensive income. Cooper Energy has not recognized a Deferred Tax Asset for Australian income tax capital losses of $15,987,262 (2013: $20,464,313) on the basis that it is not probable that the carried forward capital losses will be utilised against future assessable capital profits. Deferred income tax from corporate tax Deferred income tax at the 30 June relates to the following: Deferred tax liabilities Trade and other receivables Available for sale financial assets Oil property Exploration and evaluation Unrealised currency translation gain Deferred tax assets Oil properties Equity raising costs Trade and other payables Provision for employee entitlements Provisions Unrealised currency translation loss Tax losses Consolidated Statement of Financial Position Consolidated Statement of Comprehensive Income 2014 $’000 2013 $’000 2014 $’000 2013 $’000 1,790 3,616 1,826 (1,526) - 1,624 12,637 122 - 2,264 7,886 197 919 849 - (166) (4,751) (7,452) 83 (205) 16,173 13,963 - 15 42 512 1,173 - - 1,742 - 19 - 315 996 - 3,831 5,161 - (3) 7 (97) 388 - - (4) (357) 5 8 - (3,499) 3,831 Carry back losses – adjustment to deferred tax assets recognised - (300) - - Deferred tax income (expense) (4,278) (5,866) Deferred tax liability from corporate tax 14,431 9,102 Deferred income tax from petroleum resource rent tax Deferred income tax 30 June relates to the following: Deferred tax liabilities Exploration and evaluation 74 - - - 1,214 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 20145. Income Tax continued Income Tax Losses continued Deferred tax assets Oil properties As represented on the Consolidated Statement of Financial Position, deferred tax asset Consolidated Statement of Financial Position Consolidated Statement of Comprehensive Income 2014 $’000 2013 $’000 2014 $’000 2013 $’000 - - - - - (12,233) (11,019) As represented on the Consolidated Statement of Financial Position, net deferred tax liability 14,431 9,102 6. 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. The following reflects the income and share data used in the basic and diluted earnings per share computations: Net profit 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 dilution Basic earnings per share for the period (cents per share) Diluted earnings per share for the period (cents per share) Net profit 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 dilution Basic earnings per share for the period (cents per share) Diluted earnings per share for the period (cents per share) Consolidated 2014 $’000 22,182 2013 $’000 1,715 2014 Thousands 2013 Thousands 329,377 329,100 341,666 338,056 6.7 6.5 0.5 0.5 Consolidated 2014 $’000 21,950 2013 $’000 1,318 2014 Thousands 2013 Thousands 329,377 329,100 341,666 338,056 6.7 6.4 0.4 0.4 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. If the performance rights are vested in full, then 14,748,003 shares would be issued over the next three years. 75 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 20147. Cash and Cash Equivalents and Term Deposits Current Assets Cash at bank and in hand Short term deposits at banks (i) Non-Current Assets Term deposits at bank (ii) Consolidated 2014 $’000 7,671 2013 $’000 6,154 39,507 37,000 47,178 43,154 1,919 4,766 (i) Short term deposits at the banks are in Australian dollars and are for periods of up to 12 months and earn interest at money market interest rates. (ii) The non-current term deposits at bank consist of a deposit of US$1.5m which matures on 15 August 2014 at a fixed interest rate of 0.18% . The term deposit has been pledged to the bank to underwrite performance bonds issued by a wholly owned subsidiary. The carrying value of the term deposit approximates its fair value. The Company has a bilateral facility agreement for bank facilities totalling $40 million with Westpac Banking Corporation. Tranche A $10 million is available for issuing bank guarantees and cash advances (sub limit $5 million). As at 30 June 2014 bank guarantees of $2,627,000 (2013:$nil) in relation to performance bonds on exploration permits were issued against the facility. Tranche B $30 million is subject to satisfaction of certain conditions precedent before draw down. Reconciliation of net profit after tax to net cash flows from operating activities Net Profit for the Year Adjustments for: Amortisation of development costs in areas of production Amortisation of exploration costs in areas under production Depreciation of property, plant and equipment Exploration and evaluation written off Impairment of Non-Current Assets (Profit)/Loss on sale of investments Share based payments Finance cost – accretion of rehabilitation cost Unrealised foreign currency translation loss (Increase)/decrease in trade and other receivables (Increase)/decrease in inventories (Increase)/decrease in prepayments (Increase)/decrease in deferred tax assets (Decrease)/increase in deferred tax liabilities (Decrease)/increase in trade and other payables (Decrease)/increase in current tax liability (Decrease)/increase in provisions (Decrease)/increase in held for sale assets Net cash from operating activities 76 21,950 1,318 5,650 1,112 486 1,261 3,064 4,575 1,513 292 1,493 - - (346) 1,283 296 607 631 39 111 8,556 (7,484) (85) 25 - - 1,051 5,040 100 (138) (15) (560) 12,233 4,952 (487) (3,706) (565) (1,540) 50,258 12,454 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 20148. Trade and other receivables (current) Trade receivables (i) Related party receivables (ii) Related party receivables – joint ventures (iii) Interest receivable (i) Trade receivables are non-interest bearing and are generally on 30-90 days terms. There are no past due or impaired receivables and none that have a history of past default. (ii) All related party receivables are current within agreed terms of trade and do not exceed 180 days. (iii) Related party receivables for joint ventures are for work to be undertaken in the near term and are within contractual arrangements. (iv) Due to the short-term nature of the trade and other receivables, the carrying value approximates fair value. 9. Prepayments (current) Bank facility fee Insurance Consolidated 2014 $’000 9,765 787 217 132 2013 $’000 17,623 614 1,050 170 10,901 19,457 333 399 732 500 257 757 10. Exploration assets held for sale and discontinued operations In June 2013 the Board resolved to dispose of its exploration assets in Tunisia and withdrew from exploration assets in Poland. Management is in the process of obtaining expressions of interest from third parties for the Company’s equity holding in its Tunisian exploration activities. The losses from the exploration assets classified as held for sale are presented on a separate line in the Consolidated Statement of Comprehensive Income. Exploration and evaluation assets held for sale Liabilities associated with assets held for sale Net assets directly associated with disposal group (Loss)/Profit for the year from discontinued operations Impairment loss recognised on the re-measurement to fair value (Loss)/Profit for the year from discontinued operations Basis (loss)/earnings per share from discontinued operations (cents per share) Diluted (loss)/earnings per share from discontinued operations (cents per share) Liabilities associated with assets held for sale include a provision for restoration of $1,500,000. 2014 $’000 2013 $’000 46,906 23,809 (2,740) (573) 44,166 23,236 (232) (397) - - (232) (397) (0.07) (0.07) (0.12) (0.12) 77 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 2014 11. Available for sale investments (non-current) Shares at fair value A reconciliation of the movement during the year is as follows:- Opening balance Purchases Sale of investment Fair value movement through available for sale investment reserve Closing balance 12. Oil properties (non-current) Regions of focus Australia Asia Africa European Total oil properties Consolidated Year end 30 June 2014 Carrying amount at 1 July 2013 Additions Foreign currency adjustment Depreciation Carrying amount at 30 June 2014 As at 30 June 2014 Cost Accumulated depreciation Year end 30 June 2013 Carrying amount at 1 July 2012 Additions Depreciation Carrying amount at 30 June 2013 As at 30 June 2013 Cost Accumulated depreciation 78 2014 $’000 2013 $’000 26,040 20,182 20,182 62 - 13,203 10,172 (816) 5,796 (2,377) 26,040 20,182 2014 $’000 2013 $’000 16,778 15,839 1,515 1,577 - - - - 18,293 17,416 Total $’000 17,416 7,562 77 261 - (1,112) 2,438 7,301 77 (5,650) (6,762) 15,855 18,293 5,063 26,080 31,143 (2,625) (10,225) (12,850) 2,438 15,855 18,293 4,053 749 (1,513) 3,289 4,802 (1,513) 3,289 14,998 19,051 3,704 4,453 (4,575) (6,088) 14,127 17,416 18,702 23,504 (4,575) (6,088) 14,127 17,416 Transferred Exploration and Evaluation Development $’000 $’000 3,289 14,127 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 201413. Other property, plant & equipment (non-current) Consolidated Year end 30 June Carrying amount at 1 July Additions Disposals/written off Depreciation Carrying amount at 30 June As at 30 June Cost Accumulated depreciation 14. Exploration and evaluation (non-current) Regions of focus Australia Asia Africa European Total 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 Expenditure Exploration acquired Transferred to oil properties Unsuccessful exploration wells written off (i) Exploration expenditure classified as held for sale Carrying amount at 30 June Consolidated 2014 $’000 2013 $’000 1,464 281 (118) (486) 1,141 1,919 (778) 1,141 137 1,619 - (292) 1,464 1,756 (292) 1,464 Consolidated 2014 $’000 2013 $’000 83,702 10,919 26,287 4,559 - - - - 94,621 30,846 30,846 45,747 42,443 (261) 42,546 14,259 92 (749) (1,261) (1,493) (22,893) (23,809) 94,621 30,846 (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. 79 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 201415. Trade and other payables (current) Trade payables (i) Other payables (i) Accruals Related party payables – joint arrangements (ii) (i) Trade and other payables are non-interest bearing and are normally settled on 30-90 day terms (ii) Related party payables are accrued expenditure incurred on joint arrangements 16. Provisions (non-current) Long service leave provision Restoration provision Movement in carrying amount of the restoration provision: Carrying amount at 1 July Additional provision Provision through BMG asset acquisition Increase through accretion Carrying amount at 30 June Consolidated 2014 $’000 5,504 - 2,117 7,621 5,275 2013 $’000 4,785 358 2,143 7,286 4,559 12,896 11,845 104 41,256 41,360 3,321 1,077 36,601 257 4 3,321 3,325 3,240 42 - 39 41,256 3,321 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 at the relevant time 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 provision as at 30 June 2014 equalled 3.7% (2013: 3.54%). 17. Financial liabilities (non-current) Success fee financial liability Movement in carrying amount of the success fee financial liability: Obligation through BMG asset acquisition Increase through accretion Carrying amount at 30 June 4,004 3,965 39 4,004 - - - - 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 BMG assets acquired on 7 May 2014. The discount rate used in the calculation of the liability as at 30 June 2014 equalled 3.7% (2013: 0%). 80 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 201418. Contributed equity and reserves Share capital Ordinary shares Issued and fully paid Effective 1 July 1998, the Corporations legislation in place abolished the concepts of authorised capital and par value shares. Accordingly, the Parent does not have authorised capital nor par value in respect of its issued shares Fully paid ordinary shares carry one vote per share and carry the right to dividends Movement in ordinary shares on issue At 1 July 2013 Issuance of shares for Performance Rights At 30 June 2014 Reserves Consolidated 2014 $’000 2013 $’000 114,625 114,570 Thousands $’000 329,100 114,570 136 55 329,236 114,625 Consolidation reserve $’000 Foreign Currency Translation Reserve $’000 Share based payment reserve $’000 Option premium reserve $’000 Available for sale investment reserve $’000 Consolidated At 30 June 2012 Other comprehensive income Transferred to issued capital Share-based payments At 30 June 2013 Other comprehensive income Transferred to issued capital Share-based payments At 30 June 2014 Nature and purpose of reserves Consolidation reserve (541) - - - (541) - - - - - - - - (164) - - (541) (164) - (106) 737 3,750 - (55) 1,283 4,978 3,119 25 (1,995) (2,377) - - - - - Total $’000 608 (2,377) (106) 737 25 (4,372) (1,138) - - - 7,514 - - 25 3,142 7,350 (55) 1,283 7,440 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 an Australian dollar loan and the 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 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. Available for sale investment 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. 81 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 2014 18. Contributed equity and reserves continued Retained earnings Movement in retained earnings were as follows: Balance 1 July Net profit for the year Balance at 30 June Capital Management Consolidated 2014 $’000 2013 $’000 23,778 22,460 21,950 45,728 1,318 23,778 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’s capital management, amongst other things, aims to ensure that it meets financial covenants attached to its finance facilities that form part of its capital structure requirements. The Group currently has no interest bearing debt. 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, or issue new shares. No changes were made in the objectives, policies or processes during the years ended 30 June 2014 and 30 June 2013. The company has no current plans to adjust the capital structure. 19. Financial risk management objectives and policies The Group’s principal financial instruments comprise cash and short term deposits, receivables, available for sale investments and payables. 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 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 taken to manage any of the risks identified below. 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. Fair value hierarchy All financial instruments for which fair value is recognised or disclosed are categorised within the fair value hierarchy, described as follows, and based on the lowest level input that is significant to the fair value measurement as a whole: Level 1 — Quoted market prices in an active market (that are unadjusted) for identical assets or liabilities Level 2 — Valuation techniques (for which the lowest level input that is significant to the fair value measurement is directly or indirectly observable) Level 3 — Valuation techniques (for which the lowest level input that is significant to the fair value measurement is unobservable) For financial instruments that are recognised at fair value on a recurring basis, the Group determines whether transfers have occurred between Levels in the hierarchy by re-assessing categorisation (based on the lowest level input that is significant to the fair value measurement as a whole) at the end of each reporting period. 82 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 201419. Financial risk management objectives and policies continued Set out below is an overview of financial instruments held by the Group, with a comparison of the carrying amounts and fair values as at 30 June 2014: Consolidated Financial assets Cash and cash equivalents Term deposits Available for sale investments Trade and other receivables Financial liabilities Trade and other payables Success fee financial liability Carrying amount Fair value Level 2014 $’000 2013 $’000 2014 $’000 2013 $’000 1 1 1 1 1 3 47,178 1,919 26,040 10,901 43,154 4,766 20,182 19,457 47,178 1,919 26,040 10,901 43,154 4,766 20,182 19,457 12,896 11,845 12,896 11,845 4,004 - 4,004 - The financial assets and liabilities of the Group are recognised in the consolidated statement of financial position in accordance with the accounting policies set out in Note 2. The following summarises the significant methods and assumptions used in estimating the fair values of financial instruments: Trade and other receivables The carrying value is a reasonable approximation of fair value due to the short-term nature of trade receivables. Available for sale investments The fair value of available for sale investments 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. Trade and other payables The carrying value is a reasonable approximation of fair value due to the short-term nature of trade payables. Success fee financial liability The success fee liability is the fair value of the Group’s liability to pay a $4,004,000 success fee upon the commencement of commercial production of hydrocarbons on the Group’s BMG assets acquired on 7 May 2014. Refer to Note 17 for details. The significant unobservable valuation input for the success fee financial liability includes: a probability of 10% that no payment is made, a probability of 30% the payment is made in 2018 and a 60% probability of the payment is made in 2028; and discount rate of 3.7%. 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 2014 and 30 June 2013. 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 2014 and 30 June 2013 • The impact on equity is the same as the impact on profit before tax. 83 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 2014 19. Financial risk management objectives and policies continued Market risk continued a) Foreign currency risk The Group has transactional currency exposure arising from all its sales which are denominated in United States dollars, whilst almost all its costs are denominated in the Group’s functional currency of Australian dollars. In addition the Group operates internationally and is exposed to foreign exchange risk arising from various currency exposures, to the United States dollars, Euro’s and Polish Zloty’s. 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, Euro’s and Polish Zloty’s. 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 Term deposits at bank Trade and other receivables (current and non-current) Financial liabilities Trade and other payables Consolidated 2014 $’000 5,269 1,618 4,531 2013 $’000 3,637 4,286 18,076 2,897 641 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. Impact on after tax profit 2014 $’000 2013 $’000 (775) 947 (2,351) 2,818 Impact on other comprehensive income 2014 $’000 (15) 18 2013 $’000 - - If the Australian dollar were higher at the balance date by 10% If the Australian dollar were lower at the balance date by 10% If the Australian dollar were higher at the balance date by 10% If the Australian dollar were lower at the balance date by 10% 84 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 2014 19. Financial risk management objectives and policies continued b) Commodity Price risk Commodity price risk arises from the sale of oil denominated in US dollars. The Group does not sell forward any of its oil and has no financial instruments at report date that relates to commodity prices. The Group has provisional sales at 30 June 2014 of $5,835,000 (2013: $12,034,000). 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% Impact on after tax profit 2014 $’000 593 (593) 2013 $’000 1,203 (1,203) c) Interest rate risk The Group has no borrowings at 30 June 2014 (2013: $ nil) nor has the Group drawn and repaid any loans from a financial institution during the reporting period. The Group has interest bearing deposits of $39,506,670 (2013: $41,766,000). 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 2014 $’000 44 (39) 2013 $’000 80 (80) Credit risk arises from the financial assets of the Group which comprise cash and cash equivalents and trade and other 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 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. 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 weekly basis including cash flow forecasts to determine the forecast liquidity position and maintain appropriate liquidity levels. Trade and other payables amounting to $12,896,000 (2013: $11,845,000) are payable within normal terms of 30 to 90 days. Financial liability amounting to $5,000,000 (undiscounted) will be payable upon the commencement of commercial production of hydrocarbons on the Group’s BMG assets. The timing of this payment is uncertain but not expected to be within one year. 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. 85 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 201419. Financial risk management objectives and policies continued Share price risk Share price risk arises from the movement of share prices on a prescribed stock exchange. The Group has available for sale investments the fair value of which fluctuates as a result of movement in the share price. Impact on available for sale investment reserve Impact on profit before tax 2014 $’000 2013 $’000 2014 $’000 2013 $’000 If the share price were 10% higher at the balance date 2,604 1,958 - - If the share price were 10% lower at the balance date - - (2,604) (1,958) 20. 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 Consolidated 2014 $’000 2013 $’000 277 778 - 312 2,058 - 1,055 2,370 The Parent entity leases a suite of offices in Adelaide from which it conducts its operations. The lease is for a further four years with an option to renew after that date. Exploration capital commitments not provided 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 11,742 19,228 - 32,057 39,161 - 30,970 71,218 As at 30 June 2014 the Parent entity has bank guarantees for $4,520,000 (2013: $4,454,000). These guarantees are in relation to performance bonds on exploration permits, security on the Company’s MasterCard facilities and guarantees on office leases. 86 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 201421. 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, Tunisia and Indonesia. The Group has the following interests in joint arrangements in the following major areas: a) Joint Arrangements in which Cooper Energy Limited is the operator/manager Ownership Interest 2014 2013 Oil and gas exploration 33.33% 33.33% Australia PEL 186 VIC/L26 VIC/L27 VIC/L28 Indonesia Sukananti KSO Sumbagsel PSC Merangin III PSC Tunisia Oil and gas exploration and production Oil and gas exploration and production Oil and gas exploration and production Oil and gas exploration and production Oil and gas exploration Oil and gas exploration Bargou Exploration Permit Oil and gas exploration Nabeul Exploration Permit Oil and gas exploration b) Joint Arrangements in which Cooper Energy Limited is not the operator/manager Australia PEL 90 PEL 93 PEL 100 PEL 110 PEL 494 PEL 495 PEP 150 PEP 168 PEP 171 PEP 151 PPL 207 PRL 32 PRL 85-104* (Formerly PEL 92) Tunisia 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 Oil and gas exploration Oil and gas exploration and production Oil and gas exploration Oil and gas exploration and production 65% 65% 65% 55% 100% 100% 30% 85% - - - 55% 100% 100% 30% 85% 25% 30% 25% 30% 19.167% 19.167% 20% 30% 30% 20% 50% 25% 75% 30% 30% 25% 20% - 65% 20% 50% 25% 75% 30% - 25% Hammamet Exploration Permit Oil and gas exploration 35% 35% Poland MUA 1& 2 *Includes associated PPL’s Oil and gas exploration - 40% 87 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 2014 22. Related parties The Group has a related party relationship with its subsidiaries, joint arrangements (see note 21) 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) Mr J.W. Schneider Ms A. Williams (Appointed 28 August 2013) Mr L. Shervington (Resigned 7 November 2013) Executives at year end Executive Directors Mr D.P. Maxwell Mr H.M. Gordon Mr J. de Ross (Chief Financial Officer and Company Secretary – appointed as Company Secretary 25 November 2013) Ms A. Evans (Legal and Company Secretary) Mr I. MacDougall (Operations Manager – appointed 1 February 2014) Mr A. Thomas (Exploration Manager) The key management personnels’ remuneration included in General Administration (see note 4) are as follows: Consolidated 2014 $ 2013 $ 3,149,451 3,369,720 - 36,470 123,832 108,348 799,626 506,843 - 571,860 4,072,909 4,593,241 Short-term benefits Long-term benefits Post-employment benefits Performance Rights Early Termination payments Total 88 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 2014 22. Related parties continued Subsidiaries The Group financial statements include the financial statements of Cooper Energy Limited and the subsidiaries listed in the following table. Name Cooper Energy Indonesia Limited Cooper Energy Sukananti Limited Country of incorporation British Virgin Islands British Virgin Islands Equity interest 2014 % 100% 100% 2013 % 100% 100% Cooper Energy Sumbagsel Limited British Virgin Islands 100% 100% Cooper Energy Merangin III Limited CE Tunisia Bargou Ltd CE Hammamet Ltd CE Nabeul Ltd Cooper Energy (Seruway) Pty Ltd Worrior (PPL 207) Pty Ltd CE Poland Pty Ltd Somerton Energy Limited Essential Petroleum Exploration Pty Ltd CE Poland Coopertief UA CE Polska sp z.o.o. Joint arrangements British Virgin Islands British Virgin Islands British Virgin Islands British Virgin Islands Australia Australia Australia Australia Australia Netherlands Poland 100% 100% 100% 100% 100% 100% 100% 100% 100% 99% 100% 100% 100% 100% 100% 100% 100% 100% 100% 99% 100% 100% During the reporting period, the Group provided geological and technical services to joint arrangements it manages at a cost of $1,929,000 (2013: $1,772,000). At the end of the financial period, $1,004,000 was outstanding for these services (2013: $614,000). An impairment assessment is undertaken each financial year of related party receivables by examining the financial position of the related party and their investment in the respective joint ventures which are prospecting for hydrocarbons to determine whether there is objective evidence that a related party receivable is impaired. When such objective evidence exists, the Group recognises an allowance for the impairment loss. 89 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 2014 23. Share based payment plans On 16 December 2011 shareholders of Cooper Energy approved the establishment of an Employee Performance Rights Plan whereby the Board can, subject to certain conditions, issue performance rights to employees to acquire shares in the parent entity. During the financial year, issues were made on November 2013 and April 2014. The performance rights were issued for no consideration. The right extends to the holder the right to be vested with shares in the parent entity. Vesting 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. The vesting test is two parts. Up to 25% of the eligible rights to vest 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 rights 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. Information with respect to the number of performance rights granted to employees is as follows: Number of rights granted Average share price at commencement date of grant (cents) Average contractual life of rights at grant date in years Remaining life of rights in years Date Granted 1 July 2012 2 August 2012 10 December 2012 31 May 2013 6 November 2013 28 April 2014 597,583 252,980 5,172,342 267,607 6,581,999 312,033 $0.365 $0.437 $0.574 $0.471 $0.405 $0.510 3 3 3 3 3 3 1 1 2 2 3 3 Number of rights Number of rights 2014 2013 8,561,370 5,855,831 6,894,032 6,290,512 (135,588) (405,667) - - (571,811) (3,179,306) 14,748,003 8,561,370 1,704,527 nil 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 resignation Balance at end of year Achieved at end of year 90 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 2014 23. Share based payment plans continued The fair value of services received in return for the performance rights granted are measured by reference to the fair value of performance rights granted. The estimate of the fair value of the services received is measured based on the Black-Scholes methodology to produce a Monte-Carlo simulation model that allows for the incorporation of market based performance hurdles that must be met before the shares vest to the holder. Fair value assumptions Fair value at measurement date Share price Risk free interest rate Expected volatility Dividend yield Fair value assumptions Fair value at measurement date Share price Risk free interest rate Expected volatility Dividend Yield Fair value assumptions Fair value at measurement date Share price Risk free interest rate Expected volatility Dividend Yield Fair value assumptions Fair value at measurement date Share price Risk free interest rate Expected volatility Dividend Yield Fair value assumptions Fair value at measurement date Share price Risk free interest rate Expected volatility Dividend Yield 1 July 2012 26.1 cents 36.5 cents 3.27% 40% 0% 2 August 2012 40.6 cents 48.5 cents 2.65% 42% 0% 10 December 2012 45.8 cents 58.5 cents 2.64% 43% 0% 31 May 2013 24.9 cents 38 cents 2.59% 44% 0% 6 November 2013 31.2 cents 40.5 cents 2.82% 48% 0% 91 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 201423. Share based payment plans continued Fair value assumptions Fair value at measurement date Share price Risk free interest rate Expected volatility Dividend Yield 24. Auditors remuneration 28 April 2014 36.0 cents 51.0 cents 2.72% 49% 0% Consolidated 2014 $ 2013 $ 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 201,220 184,427 Other services Amounts received or due and receivable by related practices of Ernst & Young Australia for: Auditing and review of financial reports of an entity in the consolidated group 25. Parent entity information Information relating to Cooper Energy Limited Current Assets Total Assets Current Liabilities Total Liabilities Issued capital Retained profits Option premium reserve Unrealised (loss)/gain on available for sale financial assets Share based payment reserve Total shareholders’ equity Profit/(loss) of the parent entity Total comprehensive income/(loss) of the parent entity 92 - - 201,220 184,427 - - 201,220 184,427 Parent Entity 2014 $’000 2013 $’000 54,535 60,804 240,278 161,140 12,961 72,339 9,773 22,030 114,625 114,570 45,168 24,144 25 3,141 4,980 25 (3,381) 3,752 167,939 139,110 21,024 451 6,522 (2,930) NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 201425. Parent entity information continued 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 26. Events after the reporting period Edward Glavas was appointed as the Commercial and Business Development Manager on 4 August 2014. Parent Entity 2014 $’000 2013 $’000 277 778 - 312 2,058 - 1,055 2,370 93 NOTES TO THE FINANCIAL STATEMENTFor the year ended 30 June 2014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 2014 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 2014. Signed is accordance with a resolution of the Directors. Mr John C. Conde AO Chairman 18 August 2014 Mr David P. Maxwell Director 94 A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 95 A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 96 A member firm of Ernst & Young Global Limited Liability limited by a scheme approved under Professional Standards Legislation 97 SECURITIES EXCHANGE AND SHAREHOLDER INFORMATION as at 31 August 2014 Listing The company’s shares are quoted on the Australian Securities Exchange under the code of “COE”. Number of Shareholders There were 5,138 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 2014) Size of Shareholding Number of holders Number of Shares % of issued capital 1 - 1,000 1,001 - 5,000 5,001 - 10,000 10,001 - 100,000 100,001 - 9,999,999,999 Total Unquoted Options on Issue Nil Unquoted Performance Rights 1,120 1,441 854 1,532 191 5,138 335,363 4,133,351 7,113,607 49,022,881 268,630,307 329,235,509 0.10 1.26 2.16 14.89 81.59 100.00 Number of Holders of Performance Rights Total Performance Rights 24 14,748,003 Unmarketable Parcels There were 1,132 members, representing 347,606 shares, holding less than a marketable parcel of 1,053 shares in the company. Twenty Largest Shareholders Rank Name Units % of Issued Capital 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. 12. 13. 14. 15. 16. 17. 18. 19. 20. J P Morgan Nominees Australia Limited National Nominees Limited Chesser Nominees Pty Ltd HSBC Custody Nominees (Australia) Citicorp Nominees Pty Limited Beach Energy Limited Cairnglen Investments Pty Ltd Citicorp Nominees Pty Limited Cairnglen Investments Pty Ltd Mirrabooka Investments Limited Kavel Pty Ltd Token Nominees Pty Ltd Kellyvale Nominees Pty Ltd HSBC Custody Nominees (Australia) 2001 BFQ Nominees Pty Ltd BNP Paribas Noms Pty Ltd BFQ Nominees Pty Ltd HSBC Custody Nominees (Australia) Super Corp A/C> Bresrim Nominees Pty Ltd Token Nominees Pty Ltd 53,974,863 28,920,431 27,686,458 25,913,002 19,306,571 16,934,470 6,152,565 5,139,297 3,071,721 3,000,000 2,768,482 2,651,050 2,571,303 2,416,406 2,225,000 2,214,218 2,165,728 1,903,756 1,610,970 1,598,732 16.39 8.78 8.41 7.87 5.86 5.14 1.87 1.56 0.93 0.91 0.84 0.81 0.78 0.73 0.68 0.67 0.66 0.58 0.49 0.49 Totals: Top 20 holders of Ordinary Fully Paid Shares (Total) 211,531,009 64.28 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 Beach Energy Limited Kinetic Investment Partners Limited Acorn Capital National Australia Bank Limited 98 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 60,590,884 20,924,029 8,987,550 17,610,891 18.41% 7.15% 6.56% 5.351% SHAREHOLDER INFORMATION Share Registry 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 the half-yearly report, company press releases, investor packs, presentations and Open Briefings. 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 Computershare Investor Services Pty Ltd 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 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. 99 Notes 100 Corporate Directory Directors John C Conde AO, Chairman David P Maxwell Hector M Gordon Jeffery W Schneider Alice J M Williams (appointed 28 August 2013) Company Secretaries Alison M Evans Jason de Ross (appointed 25 November 2013) Registered Office and Business Address Level 10, 60 Waymouth Street Adelaide, South Australia 5000 Telephone: + 618 8100 4900 Facsimile: + 618 8100 4997 E-mail: customerservice@cooperenergy.com.au Website: www.cooperenergy.com.au Auditors Ernst & Young 121 King William Street Adelaide, South Australia, 5000 Solicitors Johnson Winter & Slattery Level 9 211 Victoria Square Adelaide SA 5000 Bankers Westpac Banking Corporation Level 18, 91 King William Street Adelaide, South Australia, 5000 National Australia Bank Limited Level 2, 22 King William Street Adelaide, South Australia, 5000 Commonwealth Bank of Australia Level 8, 100 King William Street Adelaide, South Australia, 5000 Citibank N.A. 2 Park Street Sydney, New South Wales 2000 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 C O O P E R E N E R G Y A N N U A L R E P O R T 2 0 1 4 

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