2018 ANNUAL REPORT Smarter business energy. Welcome to simply smarter business energy. ERM Power is an Australian energy company operating electricity sales, generation and energy solutions businesses. The Company has grown to become the second largest electricity provider to commercial businesses and industrials in Australia by load1. A growing range of energy solutions products and services are being delivered, including lighting and energy efficiency software and data analytics, to the Company’s existing and new customer base. ERM Power also sells electricity in several markets in the United States. The Company operates 662 megawatts of low emission, gas-fired peaking power stations in Western Australia and Queensland. Contents 04 Performance highlights Chairman and Managing Director’s report Supporting renewable energy Board of Directors’ profiles Executive team profiles Our business model Efficient energy fuelling 18 business and prosperity 19 Operating and financial review 20 Financial year highlights Outlook and future prospects 21 Review of operating and financial results 23 06 08 10 14 16 Corporate social responsibility Leadership Customers Workplace Community Environment Risk framework and management Directors’ report Remuneration report Annual financial statements Directors’ declaration Independent Auditor’s report Shareholder information Corporate information 36 36 36 36 37 37 38 40 43 55 117 118 125 127 ERM Power Limited ABN 28 122 259 223 shares are traded on the Australian Securities Exchange under the symbol EPW. This review is for ERM Power (Company, Group, we, our) for the year ended 30 June 2018 with comparison against the previous corresponding period ended 30 June 2017 (previous period, previous year or comparative period). All reference to $ is a reference to Australian dollars unless otherwise stated. Individual items totals and percentages are rounded to the nearest approximate number or decimal. Some totals may not add down the page due to rounding of individual components. 1 Based on ERM Power analysis of latest published information POWERED WITH positive people t r o p e R l a u n n A 8 1 0 2 3 Performance highlights 2018 at a glance ERM Power’s strong financial results for 2018 reflect a good year of growth and record sales for the Australian businesses. In a year in which the energy industry and policy remained topical and dynamic, the Company capitalised on opportunities to support commercial and industrial customers with new and innovative supply and demand products and services. The US business is held for sale following a comprehensive review to determine the best strategy for realising shareholder value. A sales transaction process is well advanced and expected to conclude in the first half of FY2019. UNDERLYING EBITDAF1 UP 25% $97.5m UNDERLYING NPAT1 UP TO $30.2m FULLY FRANKED FINAL DIVIDEND OF 4CPS & TOTAL DIVIDENDS DECLARED OF $46.3m 7.5 ¢ps RECORD AUSTRALIA RETAIL SALES VOLUME ENERGY SOLUTIONS REVENUE UP TO $18.9m R E W O P M R E 4 19.2 TWh 55 % AN ENGAGED & EMPOWERED TEAM OF EMPLOYEES of our people feel proud to work for ERM Power2 NO.1 IN CUSTOMER SATISFACTION 89 % # 1 89 % NO.1 IN BROKER SATISFACTION In customer satisfaction for the 7th year in a row 3 Consistently high level of broker satisfaction in Australia4 1 All figures continuing operations unless otherwise stated 2 Hay Group Employee Engagement and Enablement Survey, February 2017 and internal Pulse surveys FY2018 3 Utility Market Intelligence survey of large customers of major electricity retailers by independent research company NTF Group from 2011 – 2017 4 Market and Communication Research (MCR), February 2018 t r o p e R l a u n n A 8 1 0 2 5 Chairman and Managing Director’s report We are pleased to present ERM Power’s Annual Report for the financial year to 30 June 2018. FY2018 earnings increased by 25% to $97.5m (EBITDAF1), with positive results across the Australian businesses. Underlying Net Profit After Tax was $30.2m2, up $46.3m on the prior year. A strategic review of the US business Source Power & Gas resulted in our announcement to divest these operations. The growth and potential of our Energy Solutions business and the US review determined that ERM shareholder value is best served by divestment of the US operations and a focus on value creation in our Australian business. The sale transaction process is well advanced and expected to conclude in the first half of FY2019. Energy Solutions also delivered on its revenue growth targets and harnessed strong retail customer satisfaction to deliver new solutions in this growing part of the business and market. The US business delivered strong sales growth at 6.3TWh and forward contract load of 15.6TWh while gross margin was lower than expected. ERM Power has a proud history of adapting to market change and realising opportunities in a fast-moving energy sector. This is evident in the Company’s strong financial performance in FY2018 which reflects our desire to achieve sustainable returns by doing the right thing by customers, and in turn earning their trust and growing our business. Policy uncertainty continues to characterise the energy sector but the market keeps operating and ERM Power’s core role and responsibility to its customers has never been more important. We shield customers from the volatility of the wholesale market and we provide them with leading energy solutions to better manage their energy productivity. Our leadership in this respect will continue. ERM Power is now the largest wholesale buyer of electricity in the National Electricity Market (NEM) and more than one in five businesses, governments and industrials rely on us for their electricity supply and demand solutions. Our business strategy accounts for an industry in transition, allowing us to deploy deep industry expertise and innovative approaches. Performance Oakey and Neerabup Power Stations continued to deliver outstanding availability and overall performance, while maintaining excellent safety records with no lost time injuries. Power station earnings increased 5% on the prior year demonstrating the value of gas-fired assets in the transition to renewables. The performance of our Australian electricity retailing business is underpinned by our industry-leading customer service, as evidenced by our number one ranking in the UMI electricity retailer customer satisfaction survey3 for the seventh year running. ERM Power achieved 92% customer satisfaction, with a record 56% of customers stating they are very satisfied, which is particularly encouraging considering the pain our customers are enduring due to increased wholesale and network prices. We exceeded both our target of 19TWh of electricity load sold and our gross margin target for the year with sales up 4% on the prior year. Contracted forward electricity sales increased to 28.9TWh reflecting the strength of the Australian franchise. R E W O P M R E 6 Capital management and dividend As part of our capital management framework, we commenced a share buyback in March 2018 to return excess capital to shareholders. The allocated capital for the buyback was $20m after allowing prudent risk buffers for business performance, payment of dividends and about $40m reserved for growth opportunities. The share buyback reflects the Company’s strong liquidity position and our confidence in the earnings outlook. As at 30 June 2018, about 1.74m shares had been bought and about $2.8m returned to shareholders. The buyback will re-commence following completion of the US sale process. The Board also declared a final dividend of 4 cents per share bringing dividends for FY2018 to 7.5 cents per share fully franked. Delivering - supply and demand Customers are increasingly aware that energy, like any volatile commodity, needs to be a closely managed business cost. We partner with big energy users to both monitor and optimise their energy productivity. In this way, we deliver value on both supply and demand by helping customers manage wholesale volatility through their retail electricity contract on the supply side of the equation and improving their energy productivity on the demand side. ERM Power is supporting the transition to renewables through offtake agreements underpinning the Lincoln Gap wind farm (126MW) and Hamilton solar farm (58MW), and through market- making financial products that provide price certainty to “firm up” the output of these projects. This strategy further supports corporate investment in renewable energy. ERM Power is proud to have pioneered these new generation products which have been strongly received in the market. Additionally, we are a major participant in the national Renewable Energy Target scheme and for calendar year 2017, we procured and surrendered over 2.6 million large-scale generation certificates and 1.3 million small-scale technology certificates. ANNUAL REPORT 2017 ERM Power has a proud history of adaping to market change and realising opportunities in a fast-moving energy sector. This is evident in the Company’s strong financial performance in FY2018 which reflects our desire to achieve sustainable returns by doing the right thing by customers, and in turn earning their trust and growing our business. Tony Bellas Chairman ERM Power has delivered a strong set of results in financial year 2017, taking Our goal is to help customers solve today’s strategic opportunities and investing for complex energy problems with growth and diversification in a disrupting smart ideas, new technology and cleaner, cheaper energy. energy market. Jon Stretch Managing Director and Chief Executive Officer LEADING CUSTOMER SERVICE In the Australian market, the 2016 Utility Market Intelligence survey1 Industry disruption reported 94% of ERM Power’s large business customers are satisfied – the highest level of customer satisfaction recorded since 2018 was characterised by energy industry reviews, reports and the survey began in 1997. This marks the sixth consecutive year public policy gyrations. These included Dr Alan Finkel’s review of that ERM Power has out-ranked all other retailers in this survey. the NEM, the National Energy Guarantee (NEG) and an Australian Competition and Consumer Commission Report into electricity In the US market, the 2016 Energy Research Consulting Group’s retailing, which necessarily went to the very structure of the NEM. survey2 of energy broker satisfaction also demonstrates our strong The current uncertain state of the energy industry is reflective of focus on customer needs and relationships, with Source Power & many factors including enormous technological change, a desire Gas placing third out of over 50 retailers. Since acquisition in 2015, by both corporates and households to deploy cleaner energy, the Source Power & Gas broker recognition rate has tripled, with 62% challenge of that transition, the complexity and cost of energy of surveyed brokers now saying they do business with Source. infrastructure, and the lack of consensus within and among governments on an integrated national energy policy framework. HIGHLY ENGAGED PEOPLE At its core, Australia needs an enduring national energy policy. This It takes great people to deliver great results. ERM Power’s is important to providing an acceptable level of investment certainty second employee engagement and enablement survey again to deliver sustainable, reliable and affordable energy. The exit of demonstrated our people are well-positioned to deliver continued older baseload power stations and growth in intermittent generation business success. has posed reliability issues and, along with the concentration of ownership of dispatchable generation, have been key factors driving up cost for energy consumers. This has been compounded by issues with the availability and price of gas. The Company’s 2017 engagement score was consistent with the highest performing organisations in the world, and its enablement score was five percentage points above the global high-performing norm3. ERM Power also ranked above the global high-performing The lack of a stable, integrated national energy policy and poor energy infrastructure planning has stifled investment that supports norms in critical areas such as confidence in leadership, clarity of the renewable energy transition. Industry and consumers urgently business strategic direction and customer focus. need a policy framework that supports investment without undermining market price transparency or competition. Failure to deliver such a policy framework will inevitably result in higher costs for energy consumers. On behalf of the Board, we would like to thank ERM Power’s staff and management team, whose innovative thinking, belief in our strategy, and focussed work ethic are the foundation of our success. We also thank our shareholders, many of whom are staff, for your support as we continue to progress our strategy at this exciting time of industry transition. Culture In this annual report and across our communications you will see we have refreshed our brand. It is important that we have a distinctive image and that we better articulate what our brand, business and people stand for. Our people have always embodied the values which are core to our brand: simplifying energy for customers; amplifying To our customers, thank you for supporting us, inspiring us, and solutions; and exemplifying the best in whatever we do. We are challenging us to do more for your business. We look forward to committed to delivering smarter energy solutions using process helping you in new and exciting ways in the coming year. and technology innovation that has long been a core competitive advantage of ERM Power. Our goal is to help customers solve today’s complex energy problems with smart ideas, new technology and cleaner, cheaper energy. We thank our fellow Directors, and in particular acknowledge ERM Power founder Trevor St Baker, who announced his resignation from the Board in July 2017. Trevor’s ongoing commitment and guidance to the Company has been invaluable. We would like to thank the staff of ERM Power for their We’d also like to take this opportunity to thank Martin Greenberg, professionalism and dedication to delivering outstanding customer who also stepped down from the Board in October 2016, for his service and our fellow directors for their insight and guidance in service and contribution and we welcome Georganne Hodges and charting ERM Power’s ongoing success. Phil St Baker to the Board. Importantly, to our loyal customers and shareholders, thank you for ERM Power is at an exciting juncture in its transformation. the trust you place in us as we continue on this journey to deliver We look forward to continuing to grow and prosper in a great energy outcomes and create shared value for all. transforming market which presents us plenty of opportunity. Tony Bellas Tony Bellas Chairman Jon Stretch Jon Stretch Managing Director and Chief Executive Officer 1 Utility Market Intelligence survey of large customers of major electricity retailers by independent research company NTF Group from 2011 – 2016. 12 Continuing operations. Earnings before interest, tax, depreciation, amortisation, impairment and net fair value gains / losses on financial instruments designated at fair value through profit and loss and other significant items. EBITDAF excludes any profit or loss from associates. 2 Energy Research Consulting Group’s (ERCG) survey of Aggregators, Brokers and Consultants (ABC) Study December 2016. Research based on survey of 22 Continuing operations. over 120 ABCs, which represents ~72% of brokered US power sales. 32 Utility Market Intelligence (UMI) Survey, Feb 2018. 3 Korn Ferry Hay Group Employee Engagement and Enablement Survey, February 2017. t r o p e R l a u n n A 8 1 0 2 7 3 Supporting Renewable Energy T ERM Power is committed to playing its part in the transition to a less emission-intensive energy sector. Seizing opportunities in a transforming market, the Company is taking a number of practical actions to support the development of Australia’s renewable infrastructure, and helping customers harness the benefits of energy efficiency solutions such as solar PV. The rapid shift away from traditional generation sources is driving the need for new products and services. R E W O P M R E 8 Solar risk management product 2018 saw the launch of ERM Power’s innovative solar risk management products which provide hedging options for wholesale market participants in a dynamic and changing energy industry. The solar products are a first of a new generation of financial instruments which respond to the rapidly evolving Australian renewables market. ERM Power developed the new products in response to strong demand from renewable project developers and corporate customers. The new products bring much-needed price discovery and transparency to renewables and support corporate investment in renewables by providing fixed price certainty for organisations wanting to hedge solar generation production. ERM Power has been a leader in product innovation within the Australian energy market for many years, and the rapid shift away from traditional generation sources is driving the need for new products and services. Liquid financial markets bring price transparency to Australian energy markets and are vital for the effective management of risk. Energy management ERM Power provides a broad portfolio of energy management solutions that make it simple for customers to take smarter energy action. Solar PV is a popular choice for customers wishing to reduce electricity costs and improve sustainability as part of an integrated energy management plan. ERM Power partners with pre-qualified suppliers to provide end to end, turnkey solar PV solutions that can be implemented individually or as part of the overall energy productivity mix. Recommendations are underpinned by data analysis and take into consideration the mix of integrated energy productivity and efficiency solutions to ensure the solar system is right sized to make the most of the customer’s capital and provide the maximum return. ENERGY SOLUTIONS CASE STUDY J. Notaras & Sons 428 tonnes of CO2 emissions saved every year 44% reduction in electricity bill In 2018 ERM Power supported hundreds of companies looking to make the shift to renewable energy for the betterment of not only their carbon footprint, but also their energy bills. ERM Power recognises the importance of keeping regional manufacturing businesses competitive by helping them reduce energy costs. In 2018, ERM Power engaged in an energy solutions project with J. Notaras & Sons – a family-owned business in the Clarence Valley Region of NSW that has been operating for over 60 years. After signing on ERM Power as their energy provider in 2018, J. Notaras & Sons engaged the Energy Solutions team at ERM Power for advice on ways to save money on their electricity bills – which were estimated at around $219,056 per year. ERM Power proposed a solar installation that would generate over 1400kWh daily, reduce energy costs and consumption significantly, and ensure J. Notaras & Sons remained competitive and resilient in the manufacturing sector, not to mention add to their sustainability credentials. This project is estimated to reduce the company’s electricity bill by 44% and save 428 tonnes of CO2 emissions per year. The Power Factor Correction unit already onsite was also replaced, which would yield an estimated $11,000 of savings per year. ERM Power recognises the importance of keeping regional manufacturing businesses competitive by helping them reduce energy costs. The project, which projects 525,611kWh of annual solar PV generation, is also estimated to save 10,700 tonnes of CO2 emissions over 25 years. This ensures the company is not only saving significant amounts on their year-to- year bills, but is also environmentally friendly now and into the future. ERM Power understands the importance of tracking the performance of projects after completion, and as part of the contract will continue to monitor the efficacy of the J. Notaras & Sons solar installation. The online monitoring system available to Energy Solutions team members will provide email notifications of any updates on the project’s performance, ensuring they can react swiftly to any changes. t r o p e R l a u n n A 8 1 0 2 9 Board of Directors' profiles Anthony (Tony) Bellas MBA, BEc, DipEd, FCPA, FAICD, FGC (London) Independent Non-Executive Chair Age: 64 Director since 1 December 2009; Chair since 21 October 2011 8.5 years’ service Albert Goller Masters Degree in Information & Telecommunications Independent Non-Executive Director Age: 67 Director since 1 January 2015 3.5 years’ service Albert brings considerable management and marketing expertise, garnered through a very successful executive career in Germany, Canada, the USA and Australia at the global multinational conglomerate Siemens AG. He was Chair and Managing Director of Siemens Ltd in Australia between 2002 and 2012. Commencing his career as an electronics engineer with Siemens in Germany in 1973, Albert held a number of senior executive positions throughout the world including President and CEO of Siemens Canada Ltd and Head of the Corporate Office for E-business in Munich, Germany. He has a Masters Degree in Information and Telecommunications from Paderborn University in Germany and was consistently nominated as one of Australia’s most influential engineers by Engineers Australia magazine between 2004 and 2010. Currently a non-executive director, from July 2013 to February 2015 Albert served as the Chair of META, an independent organisation that was funded by the Federal Government and represented the interests of Australian manufacturers across the nation. META had been established to generate innovative thinking and collaboration across manufacturing to target job growth, enhance productivity and increase export opportunities for Australian Manufacturing companies. Special Responsibilities Member of the Audit & Risk Committee and the Remuneration & Nomination Committee. Tony brings over 30 years of policy and operational experience in the energy industry to the business. Tony was previously CEO of the Seymour Group, one of Queensland’s largest private investment and development companies. Prior to joining the Seymour Group, Tony held the position of CEO of Ergon Energy, a Queensland Government-owned corporation involved in electricity distribution and retailing. Before that, he was CEO of CS Energy, also a Queensland Government-owned corporation and the State’s largest electricity generation company at that time, operating over 3,500 MW of gas-fired and coal-fired plant at four locations. Tony was Chair of the Independent Review Panel appointed in 2012 by the Queensland Government to review the government owned electricity network businesses in Queensland. The panel submitted its report to the Government in December 2012. Tony was awarded the Centenary Medal in 2001 in recognition of his distinguished career in public service, having achieved the position of Deputy Under Treasurer with Queensland Treasury, and in 2000 as an Assistant Under Treasurer, responsible for the Industry and Energy Division of Queensland Treasury heavily involved in formulating the State Government’s energy strategy. Tony is a director of the listed companies shown below and is also a director of Loch Explorations Pty Ltd, West Bengal Resources (Australia) Pty Ltd and the Endeavour Foundation. Other listed company directorships in the last three years Since June 2010 Corporate Travel Management Limited Since December 2016 intelliHR Holdings Limited Since August 2015 NOVONIX Limited Since March 2013 Shine Corporate Ltd Since June 2017 State Gas Limited Special Responsibilities Chair of the Remuneration & Nomination Committee, a member of the Audit & Risk Committee and the Health, Safety, Environment & Sustainability Committee. R E W O P M R E 0 1 Georganne Hodges Bachelor of Business Administration in Accounting from Baylor University, CPA (Texas), Member of National Association of Corporate Directors (NACD) Independent Non-Executive Director Age: 53 Director since 26 October 2016 1.5 years’ service Antonino (Tony) Iannello BCom, FCPA, SFFSIA, Harvard Business School Advanced Management Program, FAICD Independent Non-Executive Director Age: 60 Director since 19 July 2010 8 years’ service Tony brings to the business more than 30 years of banking and energy experience. Tony is Non-Executive Chair of D’Orsogna Ltd and a director of Juniper Aged Care Services. He has prior experience as a director of the listed company shown below as well as AusNet Services Ltd, Energia Minerals Ltd, HBF Health Ltd, the MG Kailis Group of Companies, the Water Corporation of Western Australia, and has been a member of The Murdoch University Senate. Prior to embarking on a career as a non-executive director, Tony was the Managing Director of Western Power Corporation until its separation into four separate businesses. Previously he held a number of senior executive positions at BankWest. Other listed company directorships in the last three years Empire Oil & Gas NL (Chair) November 2013 – March 2018 Special Responsibilities Chair of the Audit & Risk Committee and member of the Remuneration & Nomination Committee. Georganne brings over 25 years of wholesale and retail energy experience, including extensive industry experience across the energy value chain leading the finance, accounting and other back office operations of medium to large North American wholesale and retail energy companies. She is currently CFO for energy refining and marketing company Motiva Enterprises, based in Houston Texas and a board member for Big Brothers Big Sisters Lone Star, a non-profit volunteer youth mentoring organisation. Prior to mid-2016 Georganne was Chief Financial Officer and Treasurer for Spark Energy Incorporated (Nasdaq: SPKE), a US natural gas and electricity supplier serving residential and commercial customers in 16 states, where from 2013 she was responsible for corporate financial reporting, risk management, accounting, financial planning and analysis, treasury, tax and internal controls. During her time there, she successfully completed the company’s initial public offering as well as several acquisitions. Prior to joining Spark Energy, Georganne served as Vice President Finance for US company Direct Energy’s retail energy business from August 2009 to October 2012 and in various other senior financial roles prior to that. Georganne began her finance career in 1987 with Arthur Andersen, where she audited companies across the energy value chain. Georganne also holds memberships in the Houston Chapter of CPA’s and the Women’s Energy Network. Special Responsibilities Member of the Audit & Risk Committee. t r o p e R l a u n n A 8 1 0 2 1 1 Philip St Baker BEng, MAICD Non-Executive Director Age: 50 Director since 14 July 2017 1 years’ service Wayne St Baker FAICD, GDBA, Dip. Mech.Eng. Non-Executive Director Age: 71 Director since 1 March 2016 2.5 years’ service Philip is an experienced entrepreneur active in Australia and the USA. He was previously Managing Director of ERM Power for eight years to 2014 overseeing the development of power generation assets (over $2 billion in value), and the creation and expansion of ERM Power’s retail business. Prior to that Philip had a 16-year career with BHP Billiton gaining international experience in the resources sector including mining, processing, smelting and refining. In 2014 Philip received the Ernst & Young Queensland Entrepreneur of the Year Award for Listed Companies and was a nominee for the Australian Entrepreneur of the Year. Philip is also a member of State Advisory Board of Queensland for the Starlight Children’s Foundation. Other listed company directorships in the last three years NOVONIX Limited (MD & CEO) Since August 2015 Special Responsibilities Member of the Remuneration & Nomination Committee. Wayne brings to the business more than 40 years’ experience as a chair, executive director and non-executive director of listed and private companies in Australia and SE Asia across the industrial sector. Wayne is currently a non-executive director of ProComp Energy Machinery (Kunshan) Co. Ltd (China). From March 2010 to April 2016 he was a non-executive director of CAPS Australia, and until 2009 was the Managing Director of Champion Compressors, enabling the company to expand from a small private service and sales company to become a publicly listed manufacturer and market leader in Australia and Asia. Wayne has held global business development roles for divisions of United Technology Corporation (USA). Wayne was previously a non-executive director on the ERM Power Board between July 2007 and June 2010. R E W O P M R E 2 1 Jon Stretch BSc (Melb), MAICD Managing Director & CEO Age: 54 Director since 2 February 2015 3.5 years’ service Jon joined ERM Power as Managing Director and Chief Executive Officer (MD & CEO) on 2 February 2015. He also plays an advocacy role in the broader energy industry speaking at various events such as the Australian Energy Week. Jon is an experienced chief executive with broad international experience in the information technology (IT), telecommunications and industrial sectors. His background in systems and process engineering, and business-to-business (B2B) and business-to- consumer (B2C) sales and marketing has enabled him to lead business transformation and growth in Australia and internationally. Prior to joining ERM Power, Jon was the Executive Vice President, Europe, Middle East and Africa (EMEA) for Landis+Gyr, the leading provider of smart metering and energy management solutions globally. Jon joined Landis+Gyr as Executive Vice President Asia Pacific in January 2008 and in April 2010 moved to Switzerland to take up the EMEA position. Prior to joining Landis+Gyr, Jon was CEO of AAPT, an Australian based telecommunications company, wholly owned by Telecom New Zealand and was based in Sydney. He has had extensive experience in Asia and Europe in IT and telecommunications, starting his career with IBM in Australia in 1986. He spent six years in Hong Kong with IBM and AT&T running substantial cross regional telecommunications services businesses, and several years running AT&T’s business across Europe, Middle East and Africa, based in Paris. Special Responsibilities Chair of the Health, Safety, Environment & Sustainability Committee, the Workplace Health & Safety Committee, and the Enterprise Risk Committee. t r o p e R l a u n n A 8 1 0 2 3 1 Executive team profiles Mitch Anderson BS (Finance), MBA Executive General Manager, Business Energy (US) Michelle Barry BBus Executive General Manager, Corporate Affairs Gregg Buskey BE (electrical), PhD, GAICD Executive General Manager, Corporate Finance & Strategy Mitch leads Source Power & Gas, based in Houston in the United States. As the head of the US operations Mitch is responsible for planning, implementing and integrating the strategy for Source. He formerly led ERM Business Energy (AU). Mitch has more than 25 years’ experience in energy retailing and trading across Australia, the United States and New Zealand. Michelle is responsible for ERM Power’s investor relations, human resources, regulatory affairs and communications programs. Michelle has more than 20 years’ experience in media, strategy and corporate affairs roles across the energy and financial services sectors in Australia and the United Kingdom. Gregg is responsible for strategy development and corporate financing activities, both critical to the business strategy underpinning ERM Power’s growth and business plans. Gregg has more than 13 years’ experience in the energy industry and prior to that worked in robotics. Megan Houghton BCom, BA (Economics), GAICD Executive General Manager, Energy Solutions Megan is responsible for the Company’s Energy Solutions business, which delivers integrated energy management solutions to business, government and industrial customers. Megan has over 20 years’ experience in consulting, government, energy and water utilities leading business strategy, growth and transformation. R E W O P M R E 4 1 Phil Davis LLB, AGIA Group General Counsel and Company Secretary David Guiver GAICD Executive General Manager, Trading Phil heads up ERM Power’s in-house legal team and supports the Board as Company Secretary. Phil is a qualified lawyer in Australia and the United Kingdom and specialises in the corporate, construction, property, energy and resource sectors. David leads a team of energy trading specialists who source competitively priced energy risk management products. David’s team is also responsible for the commercial operations of the Company’s power station assets. David has over 20 years’ experience in electricity trading and retailing. Derek McKay MBA, BE (Mech), GAICD Chief Information Officer Executive General Manager, Generation Steve Rogers B.Comm, MAICD Executive General Manager, Energy Retail (AU) James Spence B.Sc, CA Chief Financial Officer Derek manages teams across ERM Power’s two gas-fired peaking power stations, and the Company’s technology strategy, including infrastructure support and software development. Derek has more than 25 years’ experience in the Australian gas and electricity industries. Steve leads the retailing business in Australia, which is responsible for the acquisition, retention and growth of the commercial and industrial customer base. Steve previously held commercial roles in the utilities sector and started his career as an accountant. He has more than 16 years’ experience in the energy industry. James is responsible for ERM Power’s group financial operations and risk management. James has experience in power generation, energy retailing and trading businesses in Australia, the US and United Kingdom. He has held CFO and Finance Director roles in energy businesses in Australia, UK and North America. t r o p e R l a u n n A 8 1 0 2 5 1 Our business model Our business model defines the activities that we are engaged in, the relationships we depend on and the outputs and outcomes we aim to achieve in order to create value for all our stakeholders in the short, medium and long term. Capital (resources) Value added by FINANCIAL ENERGY RETAILING We seek to efficiently source and use funds generated from operations or investments or obtained through financing. ENERGY MANAGEMENT We seek to maximise customers’ energy productivity by addressing both the supply and demand side of the energy equation. PEOPLE We continually work to develop the competencies, capabilities and talent of our people, who underpin our success. INTELLECTUAL We work with businesses and brokers to deliver efficient, timely and cost-effective electricity supply over a defined contract period. We rely on our supply chain for a number of inputs into our businesses including energy solution products and renewables certificates. PRODUCTION OF ENERGY PRODUCTS AND SERVICES We develop, deliver, install and monitor a range a energy solutions that help businesses manage their energy more efficiently, and reduce their business costs. SERVING CUSTOMERS EFFECTIVELY Through our active customer management, accurate billing and technical innovations we ensure their satisfaction and build mutually-beneficial long-term relationships. TRADING We efficiently source electricity and green certificates for our customers and manage risk through our trading practices. ENGAGING AND ENABLING EMPLOYEES Highly engaged and enabled people create high-performing organisations. Our knowledge-based assets includes our brands, proprietary technology, systems and processes. SERVING COMMUNITIES PHYSICAL Our power stations are important inputs to our value creation processes and we manage them safely, efficiently and effectively. By providing products that meet our customers needs and operating a responsible, sustainable business, we create value for the communities where we operate. INDUSTRY LEADERSHIP We advocate on behalf of businesses and seek to amplify their voice. PARTNERSHIPS We develop mutually beneficial partnerships which support our business objectives. SOCIAL AND RELATIONSHIPS SUSTAINABILITY We will protect and enhance our reputation with our stakeholders, ensuring we have the licence to operate. Energy management products and services help customers drive down costs and emissions to meet sustainability targets. R E W O P M R E 6 1 Value created We create value for our stakeholders and our business by carefully managing capital and resources. Value shared EBITDAF $97.5m Dividend yield 6.8 % CUSTOMER SATISFACTION 92 % LOAD SOLD 19.2 TWh EMPLOYMENT 335 ENGAGED AND ENABLED WORKFORCE 72_ SCORE ENGAGED at high-performing global norms 77_ SCORE ENABLED above high-performing global norms TAXES $26.9m CUSTOMER ENERGY SAVINGS 25 %* MW OF RENEWABLE ENERGY SUPPORTED ~200MW * Energy Solutions By operating a profitable and sustainable business, we create value which is shared with all our stakeholders. SHAREHOLDERS By managing all inputs into our business well, we create profits which benefit shareholders through dividend payments and share value. GOVERNMENT We contribute to state and federal government monies through tax contribution. SUPPLIERS/BUSINESS PARTNERS As we create value, we support businesses throughout our value chain, and job creation beyond our business. STAFF Engaging, developing, recognising and rewarding our staff helps us secure and retain a skilled, energetic and motivated workforce. COMMUNITIES The communities where we operate benefit through job creation, tax payments, useful products, services, minimisation of environmental impacts and philanthropy programs. CUSTOMERS We build value for our customers’ businesses through the efficient and cost-effective provision of electricity and energy solutions. INDUSTRY ERM Power executives and regulatory specialists actively participate in advocacy and government relations opportunities, sitting on various consultative forums, writing regulatory submissions and engaging with strategic stakeholders. t r o p e R l a u n n A 8 1 0 2 7 1 Efficient energy fuelling business and prosperity ERM Power has a clear, consistent strategy in place to drive the growth of its business and deliver ongoing value to shareholders. The Company’s unique dual supply/demand perspective underpins the strategy, which focusses on meeting the growing range of energy needs for business, commercial and industrial customers. Against a complex and dynamic industry backdrop, ERM Power helps provide certainty to customers who rely heavily on energy to fuel their success, through retail electricity contacts and a growing portfolio of data-driven energy management solutions. ERM Power’s customer-led strategy recognises the fundamental changes in the energy industry and empowers businesses to take control of their own energy costs. The strategy capitalises on the Company’s enduring customer relationships and seeks to broaden and deepen these to help businesses optimise their energy investment. As the energy market continues to transform, and the transition to renewables becomes more pronounced, ERM Power’s strategy also looks to take advantage of emerging opportunities, to develop and deliver responsive, innovative products and services. ERM Power’s industry insights, market-leading strength of customer service and expertise in sophisticated data modelling and analytics well positions the Company for an increasing emphasis on smart energy solutions that will help transform the way businesses use and consume energy. Equally important is the Company’s commitment to building a diverse, progressive and innovative culture that attracts and retains the high-quality talent which underpins ERM Power’s competitive advantage. ERM Power will continue to execute on its growth agenda while flexing and adapting to take advantage of opportunities presented through the evolving energy landscape, with a focus on sustained high performance and sustainable shareholder returns. Operating and Financial Review For the year ended 30 June 2018 Operating and Financial Review For the year ended 30 June 2018 Financial year highlights UNDERLYING EBITDAF1 UNDERLYING NPAT1 STATUTORY LOSS $97.5m $19.3m on FY2017 $30.2m $46.3m on FY2017 $(80.7)2 m $79.6m on FY2017 Australia retail Sales volume Gross margin Opex US retail Sales volume Gross margin Opex Generation EBITDAF ($m) Oakey Neerabup FY2018 outlook 24 August 2017 FY2018 outlook 22 February 2018 FY2018 actual ~19TWh ~19TWh 19.2TWh ~$4.40 / MWh ~$4.70 / MWh ~$23m ~$23m $4.90 / MWh $22.0m ~7.5TWh ~6.5TWh 6.3TWh ~A$5.00/MWh ~A$4.50/MWh ~A$3.20/MWh ~A$3.50/MWh A$3.28/ MWh A$3.25/ MWh $14-16m ~$26m $14-16m ~$26m $17.0m $27.6m Energy solutions EBITDAF ($m) ~($4.5)m ~($4.0)-($4.5)m ($3.6)m Corporate and other costs ($m) ~($15.5)m ~($14.5)m ($14.6)m Underlying EBITDAF from continuing operations for the Group increased $19.3m on prior period EBITDAF of $78.2m. EBITDAF increased substantially due to the performance of the Australia retail business with strong performance also from the Oakey and Neerabup power stations and increasing earnings in the growing Energy Solutions business. Underlying NPAT increased $46.3m with EBITDAF improvements in FY2018 contributing $13.5m additional after-tax earnings, and no recurrence of the one off permanent tax difference of $37.1m in FY2017 related to the Clean Energy Regulator shortfall charge. During the period the Group made decisions to divest the US energy retailing business and sell its SME single site customer contracts held in the Australian energy retailing business. As a consequence, US operating earnings are reflected in discontinued operations and the respective assets and liabilities categorised as held for sale throughout this review. The sale of the SME single site customer contracts resulted in an impairment loss of $1.0m being recognised during the period. The decision to sell the US business was taken based on the earnings forecasts of the business and the investment and time required to reach an appropriate return on investment. Under the Group’s capital management framework announced in February 2018, capital is allocated to parts of the business that the Board and management consider as providing the best value opportunities. Accordingly, the Board considered that the US business may be of more value to a US strategic buyer while ERM Power increases its focus and allocation of capital on expanding its growing Energy Solutions business in Australia. A sale process was initiated in June 2018 for the US business and the Group expects to finalise a sale during the first half of FY2019. Statutory NPAT was a loss of $80.7m and differs to underlying NPAT largely due to the unrealised net fair value movement in financial instruments and inclusion of losses incurred from the Group’s discontinued US business. The after-tax impact of the unrealised fair value movement was $76.4m and is a result of falling forward wholesale market electricity prices in 2H FY2018, on derivative instruments largely in place to manage exposures on future customer contracts which have offsetting movements, which are not included for accounting purposes. Statutory NPAT also includes the discontinued operations statutory loss results of $34.0m. 1 All figures continuing operations unless otherwise stated 2 Includes unrealised net fair value losses of $76.4m on financial instruments designated at fair value through profit and loss and loss from US discontinued operations of $34.0m R E W O P M R E 0 2 Outlook and future prospects The outlook for FY2019 is shown in the table below. Australia retail Sales volume Gross margin Opex Generation EBITDAF1 ($m) Oakey Neerabup Energy solutions ($m) Revenue EBITDAF Corporate and other costs ($m) Short surrender strategy ($m) FY2018 actual FY2019 outlook 19.2TWh ~19TWh $4.90 / MWh $22.0m ~$4.75 / MWh ~$22m $17.0m $27.6m $14-16m ~$26m $18.9m ~+50% on FY2018 ($3.6)m ~($2.5)m ($14.6)m ~($16.0)m - $35-45m NPAT in FY2019/20 (weighted to FY2020). 1 FY2019 outlook includes $1.6m generation overhead expenditure, whilst the actual result in FY2018 was $0.8m. Medium term Australia retail gross margin outlook is $4-5.50/MWh. Outlook Sales volumes in Australia retail are expected to be at or slightly ahead of FY2018 after adjusting for the sale of our SME single site book and loss of the NSW Government SME site contract. The reduction in rate of growth is due to lower volumes expected to come to market in FY2019. The mid-case margin of $4.75/MWh is in line with the range previously provided of $4-5.50/MWh, anticipating a slight reduction on the out-performance in FY2018. Opex will be in line with FY2018, and a reduction on FY2017 reflecting continued business efficiencies. As previously stated, we anticipate that the large scale generation certificates (LGC) strategy will deliver $35-45m of NPAT across FY2019&20 weighted to FY2020. The outcome and timing will be dependent on market and contractual factors. We retain the right to surrender certificates prior to 14 February 2020. This is not included in the outlook for gross margin. Our expectation is that generation earnings will be in line with previous years and slightly below FY2018 where we have seen out-performance from both assets due to tighter supply in the Western Australian market and optimisation opportunities at Oakey. Energy Solutions is expected again to see ~50% sales revenue growth as the business model continues to provide customers the opportunity to realise savings on their energy costs by making investments in energy efficiency. The EBITDAF loss is expected to reduce to around $2.5m while we continue to invest in operating capability as top line revenues of the business grow rapidly. Corporate costs are expected to increase to around $16m driven in part by increased IT costs related to the integration of the Retail and Energy Solutions businesses. t r o p e R l a u n n A 8 1 0 2 1 2 Operating and Financial Review For the year ended 30 June 2018 Future prospects ERM Power is playing to its strengths in a transforming energy market. Our strategy accounts for an industry in transition, allowing us to deploy industry expertise and innovative approaches to meet changing customer needs. This has made ERM Power a leader in customer service, underpinning the trust business energy users place in our brand and people. This positions the business strongly to deliver smart energy management solutions which are a strategic differentiator. Businesses are increasingly looking to ERM Power for ways to meet both supply and demand challenges; to help manage the volatility of the wholesale market and reduce their energy consumption, to improve commercial, social and environmental outcomes. The external environment is conducive to ERM Power’s business plan, with the need for competition clear in energy policy debate and in the recommendations of the Electricity Supply and Prices Inquiry by the Australian Competition and Consumer Commission (11 July 2018). ERM Power has a core electricity retailing business from which customer relationships are expanding into new energy management solutions. Investment in recent years has laid a solid platform for this business which is exceeding its targets. The Energy Solutions proposition is underpinned by market insights, deep knowledge of how businesses consume energy and powerful data analytics leading to compelling integrated project solutions. The Company’s generation assets are an important part of the portfolio. Gas has a critical role to play in the transition to a lower-emission electricity sector, highlighting the strategic value of ERM Power’s two gas-fired peaking power stations – Oakey Power Station in Queensland, and Neerabup Power Station in Western Australia. ERM Power continues to execute on its strategy to create a high-performing business that advocates and delivers for energy consumers and in turn, shareholders, while making a positive contribution to the communities in which it operates. R E W O P M R E 2 2 Operating and Financial Review SECTION 1: SUMMARY OF GROUP FINANCIAL RESULTS Review of operating and financial results 1. SUMMARY OF GROUP FINANCIAL RESULTS 1.1 Performance summary $m Business Energy Australia Generation Energy Solutions Corporate and other Underlying EBITDAF continuing operations Significant items Statutory EBITDAF continuing operations Depreciation and amortisation Net fair value (loss) / gain on financial instruments Share of associate profit / (loss) (net of tax) Impairment expense Finance income Finance expense (Loss) / profit before tax Tax benefit / (expense) (Loss) / profit from discontinued operations Statutory net (loss) / profit after tax (NPAT) Add back: Net fair value loss / (gain) on financial instruments (net of tax) Share of associate (profit) / loss (net of tax) Loss / (profit) from discontinued operations Significant items (net of tax) Underlying NPAT continuing operations FY2018 FY20171 Change 71.9 43.8 (3.6) (14.6) 97.5 - 97.5 (30.2) (109.2) 0.2 (1.0) 3.1 (27.3) (66.9) 20.2 (34.0) (80.7) 76.4 (0.2) 34.0 0.7 30.2 53.4 41.7 (4.3) (12.6) 78.2 - 78.2 (27.2) 50.9 (0.3) - 3.6 (24.5) 80.7 (61.5) (20.3) (1.1) (35.6) 0.3 20.3 - (16.1) 18.5 2.1 0.7 (2.0) 19.3 - 19.3 (3.0) (160.1) 0.5 (1.0) (0.5) (2.8) (147.6) 81.7 (13.7) (79.6) 112.0 (0.5) 13.7 0.7 46.3 Underlying earnings per share 12.30 (6.59) 18.89 1 FY2017 figures restated to exclude US operations now included within discontinued operations. % 35% 5% 16% (16%) 25% - 25% (11%) N/A N/A N/A (14%) (11%) N/A N/A (67%) N/A N/A N/A 67% N/A N/A N/A Underlying profits exclude the earnings associated with our US business following a decision to divest the operations as detailed in section 2.2. Accordingly, the results of the US operations are reflected in discontinued operations. t r o p e R l a u n n A 8 1 0 2 3 2 Operating and Financial Review SECTION 1: SUMMARY OF GROUP FINANCIAL RESULTS 1.2 Underlying profits from continuing operations Underlying EBITDAF movement $m 18.5 2.1 0.7 97.5 78.2 (2.0) m $ 120 100 80 60 40 20 0 FY2017 EBITDAF Business Energy AUS Generation Energy Solutions Corporate FY2018 EBITDAF Underlying EBITDAF from continuing operations for the year was $97.5m compared to $78.2m in the previous year. The key drivers of the $19.3m increase were as follows: • • • • Business Energy Australia earnings increased by $18.5m on the comparative period. During the period we continued to see an improvement in operating conditions across the business with continued benefit from our STEP product, portfolio optimisation and the Vales Point offtake agreement, as prices in NSW remained high. Gross profit margin of $4.90/MWh was above the previous outlook with lower than expected load and price variance over the second half. Operating costs decreased due to efficiencies. Generation earnings increased by $2.1m on the prior year with Neerabup contributing higher earnings in a tighter wholesale market following a number of plant outages from other generators and weather events creating merchant generation opportunities in the Western Australian market. Oakey benefited from favourable electricity hedging and the monetisation of gas positions. Energy Solutions made an EBITDAF loss of $3.6m, a $0.7m improvement on the comparative period. Energy Solutions revenue for the period was $18.9m, up ~55% compared to the prior year. Net corporate and other costs increased by $2.0m on the prior year, mainly as a result of software licence sale earnings realised in FY2017. Underlying NPAT movement $m 37.1 (2.0) (2.1) (0.2) 30.2 13.5 (16.1) FY2017 NPAT After-tax EBITDAF movement Shortfall charge After-tax finance costs After-tax depreciation Other FY2018 NPAT m $ 40 30 20 10 - (10) (20) (30) R E W O P M R E 4 2 Underlying NPAT from continuing operations was a profit of $30.2m compared to a loss of $16.1m in the previous period. The key drivers of the $46.3m increase were as follows: • • • • Net after tax impact of EBITDAF movements of $13.5m; A permanent tax difference resulting from the Clean Energy Regulator shortfall charge of $37.1m in the prior period. The decision to meet a portion of our 2016 LGC surrender requirements by way of payment of a shortfall charge to the Clean Energy Regulator in FY2017 resulted in an additional permanent tax difference as the shortfall charge was not tax deductible; After tax impact of finance cost increase of $2.0m, mainly as a result of the increased Liberty International Underwriters facility announced in July 2017 as well as associated higher prudential requirements in our Business Energy Australia operation following increased wholesale prices; and After tax impact of increased depreciation of $2.1m. Depreciation increased $1.6m in our Business Energy Australia operations, largely as a result of thigher customer acquisition costs and the associated amortisation charge. Depreciation across other parts of the business increased by $0.5m. 1.3 Cash flow $m Cash flow Operating cash flow before working capital changes Net working capital changes Operating cash flow Total investing cash flow Net drawdown / (repayment) of borrowings Net repayment of leases Finance costs Dividends paid Payments for shares bought back Termination of US Sleever agreement Effect of exchange rate changes on cash and cash equivalents Net change in cash Continuing operations FY2018 FY2018 FY2017 Change 77.1 (136.2) (59.1) (31.8) 145.4 (4.1) (24.4) (17.3) (2.9) - - 5.8 76.7 (119.5) (42.8) (43.5) 145.4 (4.4) (34.0) (17.3) (2.9) (5.1) 0.4 (4.2) 66.2 85.5 151.7 (19.8) (23.7) (4.1) (28.7) (22.5) - - (0.8) 52.1 10.5 (205.0) (194.5) (23.7) 169.1 (0.3) (5.3) 5.2 (2.9) (5.1) 1.2 (56.3) Operating cash flow before working capital changes of $76.7m were $10.5m higher than the prior year as a result of higher earnings in the Australian businesses, which were partially offset by higher tax payments made during the year following utilisation of available tax losses in FY2017. Working capital changes saw the reversal of variation margin cash paid in the groups favour in the prior year with a total outflow of $118.7m. Higher green certificate inventory balances contributed to the increase in working capital, which was partially offset by higher associated working capital liabilities. Net investing cash flows increased $23.7m on the prior year with higher spend on customer acquisition costs in our US business as a result of higher load. Investing cash flows in the prior period included the receipt of $14.9m in August 2016 from the sale of Western Australia joint venture gas interests to Empire Oil & Gas NL in February 2015 as well as $11.2m from the sale of our US residential business compared to $4.3 in FY2018. Finance costs increased on the prior period as a result of higher load sold in our US operation and the associated credit sleeving fees as well as the early termination payment of $5.1m to exit the previous sleeving arrangement used as part of our US operations. Dividend payments reduced following the reduction of the dividend paid to 3.5 cents per share fully franked. A total of $2.9m was spent buying back shares under the buy-back plan announced in February 2018, including transaction costs. Free cash decreased $58.6m primarily due to an increase in cash posted to restricted broker margin accounts, which saw restricted cash increase $41.6m from 30 June 2017. t r o p e R l a u n n A 8 1 0 2 5 2 Operating and Financial Review SECTION 1: SUMMARY OF GROUP FINANCIAL RESULTS 1.4 Balance sheet $m Balance sheet1 Net assets (including assets held for sale) Net working capital Net capital employed including working capital Net derivative balances Net (debt) / cash 1 Continuing operations only for FY2018 unless otherwise indicated FY2018 FY2017 Change 249.5 (7.0) 411.5 (14.3) (108.7) 565.9 (73.0) 369.4 305.3 55.7 (316.4) 66.0 42.1 (319.6) 164.4 Net assets decreased $316.4m from 30 June 2017. The decrease was principally as a result of a decrease in net derivative balances of $319.6m following a reduction in forward electricity market prices. The majority of this movement was reflected in changes in the Group’s hedge reserve while changes related to instruments not hedge accounted are reflected in profit and loss. Net working capital overall increased with higher levels of green certificate inventory only partially offset by an associated increase in the working capital liability. Net debt increased principally because of the reversal of variation margin cash previously posted in the Group’s favour, as shown in working capital changes in section 1.3 above. The repayment of the variation margin cash previously paid to ERM Power was a result of a decrease in wholesale prices during 2H FY2018. As a result, there was higher utilisation of the ANZ receivables facility at 30 June 2018 than in previous periods. The Group’s reported net debt is subject to fluctuate at balance date as a result of timing of working capital items, in particular settlement timing of wholesale market and counterparty payables related to our electricity retailing business in Australia. In December 2017, the $240m facility with ANZ was increased by $60m for the period from 1 January to 31 May for each year of the remaining term. This increase will support Business Energy Australia’s working capital and collateral needs during this peak period. In addition, the term of this facility was extended to July 2020. 1.5 Capital management $m Balance sheet Dividends paid (cents per share) Franking percentage FY2018 FY2017 Change 7.0 100% 9.5 36.8% (2.5) 63.2% Under the Company’s capital management framework, capital available for distribution or reinvestment is determined with consideration to the liquidity requirements of the business whilst maintaining suitable buffers. Capital not required to maintain liquidity is used firstly in the payment of an appropriate level of ordinary dividends and secondly to fund growth opportunities. Additional surplus capital beyond these requirements is distributed back to shareholders in the most appropriate form. In determining the level of ordinary dividends Directors consider the earnings outlook, sustainability of the dividend level, yield and level of payout relative to earnings. Directors intend to pay dividends bi-annually after the respective period results are published. A reduction in the ordinary dividend is only considered in the event of material earnings volatility. Consistent with the Company’s capital management framework, on 22 February 2018 the Company announced an on-market share buy-back of up to $20 million. The buy-back commenced on 12 March 2018 and will take place over a 12 month period. At 30 June 2018 1.7m shares had been acquired at a weighted cost of $1.61 per share. A fully franked final dividend of 4.0 cents per share for FY2018 was declared on 23 August 2018. An interim dividend of 3.5 cents per share was paid on 6 April 2018. Based on the share price at 30 June 2018, total dividends paid during FY2018 equate to a gross dividend yield of 6.8%. R E W O P M R E 6 2 Operating and Financial Review SECTION 2: DIVISIONAL PERFORMANCE REVIEW 2. DIVISIONAL PERFORMANCE REVIEW 2.1 Business Energy Australia ERM Power is the second largest electricity provider to Commercial and Industrial (C&I) customers in Australia and the third largest retailer in the market. ERM Power has brought competition to the Australian market based on price and service; with a number 1 customer service ranking for seven years running1. Financial result Load sold (TWh) Contestable revenue ($’000) Gross margin ($’000) Opex ($’000) Underlying EBITDAF ($’000) Statutory EBITDAF ($’000) Underlying gross margin $/MWh Underlying opex $/MWh FY2018 FY2017 Change Change % 19.2 18.5 0.7 2,046,377 1,477,818 568,559 93,938 76,025 (22,028) (22,666) 71,910 71,910 4.90 (1.15) 53,359 53,359 4.11 (1.23) 17,913 638 18,551 18,551 0.79 0.08 4% 38% 24% 3% 35% 35% 19% 7% Operational highlights During the year, there was strong growth in C&I load, which grew by 4% whilst SME load reduced by 5%. Total load sold was 19.2 TWh, up 4% on the prior year. Forward contracted load grew 1% from 28.6 TWh to 28.9 TWh reflecting our continued strong competitive position in the market. This figure includes estimated load from contracted customers on our STEP platform. The recontracting rate in FY2018 improved to 75% of load, which is above the historical average. The annual NTF Group UMI survey1 of C&I electricity customers saw ERM Power again comfortably win the survey for the 7th year running with 92% of customers either satisfied or very satisfied. This was a result achieved in a market where customers were struggling with rapidly increasing wholesale costs of energy and re-enforced our position as a trusted partner in helping our customers manage their energy costs. The survey also highlighted our Net Promoter Score amongst our customers to be +40 which is an outstanding result in any industry globally. By contrast, our major competitors were at -32 and -48 respectively. ERM Power was strongly associated with high standards of customer service and overall value for money by our customers which is a strong affirmation of our service model. The ACCC report into the Retail Electricity industry was finalised in June 2018 with a number of recommendations largely applicable to the mass market. The C&I retail market was predominantly found to be working in customers’ interests but highlighted concerns around the degree of vertical integration in wholesale markets. This applied particularly in Queensland where the ACCC found there was excessive market concentration of generation ownership by the Queensland Government. ERM Power is strongly of the view that liquid wholesale markets are essential for efficient operation of the market and ultimately delivers the best results for customers. ERM Power has successfully lobbied for the National Energy Guarantee to recognise these principles in its final design which will be the subject of Government consideration in FY2019. In June 2018 we entered into a contract for the sale of our SME single site book, which comprised about 5,200 sites. Our core electricity retailing business in C&I and SME multi-site segments where we have a strong proposition, point of differentiation and strategic advantage has seen growth and profitability. SME single site is a very different market and it has proven difficult to achieve returns equivalent to that we can achieve by deploying capital into other areas of the business. As a consequence we determined to exit the SME single site market segment by selling our customer book to Next Business Energy (Next). Sale proceeds are expected to be about $4m and will be received progressively as customer sites are transferred to Next. Proceeds of $1.5m were received during the year. At 30 June 2018 the associated contract acquisition costs for these sites were classified as held for sale and written down to the expected value of sale proceeds. Our mass market focus is now channelled through our residential retailer minority investments, 1st Energy and Energy Locals who are better placed to drive growth through their whole of mass market focus and consequent efficiencies of scale. Contract length increased in FY2018 to an average length of 2.2 years (up from 1.9 years) as some customers sought longer term contracts due to lower wholesale prices beyond the immediate forward 12 months. Our STEP online platform continues to resonate with customers. Customer numbers were tracking materially ahead of expectations due to strong interest from customers looking to spread the timing risk of their energy purchases. We expect this trend to continue as market dynamics remain volatile. In response to customers’ increased interest in directly contracting with renewable energy projects, and the increased proportion of electricity supply being provided by intermittent generation, ERM Power developed two new innovative derivative products in order to further facilitate price transparency and market liquidity in additional energy market hedging instruments. One product emulates a typical single-axis tracking solar generator’s production profile, and includes both an electricity hedge and a matching amount of LGCs on a one LGC to one MWh basis. The second product is an electricity only product, and is a hedge for all of the non-solar hours. 1 Refers to the Utility Market Intelligence (UMI) survey between 2011 and 2017 of large customers of major electricity retailers in Australia by independent research company NTF Group t r o p e R l a u n n A 8 1 0 2 7 2 Operating and Financial Review SECTION 2: DIVISIONAL PERFORMANCE REVIEW Financial performance Gross margin per MWh increased on the prior year as a result of strong operating performance across the business. During the year we continued to see an improvement in operating conditions with continued benefit from portfolio optimisation and the Vales Point offtake agreement, as prices in NSW remained high. Gross profit margins of $4.90/MWh were above the previous outlook. As disclosed previously, under the LGC scheme ERM Power elected to pay the shortfall charge of $65 per certificate in FY2017 and take up the 3 year optionality period available to potentially acquire certificates through either the market or through securing certificates directly from new renewable generators to assist with obtaining financial close of such projects. ERM Power has a further 1.5 years available under the optionality period to surrender large scale generation certificates. A small volume of certificates (20,000) were remitted during FY2018 for the previous shortfall amount, generating a refund of $1.3m. Included within gross margin during the period were timing variances from portfolio optimisation activities including the early settlement of electricity futures contracts. Portfolio optimisation of positions for both black electricity and environmental commodity products is a normal part of operations and may involve early settlement of derivative financial instruments, which may be positive or negative. If these instruments do not qualify for hedge accounting, any realised gain or loss is recognised immediately in profit and loss regardless of the original settlement date. Operating expenditure decreased $0.6m on the prior year as a result of efficiencies across the business. R E W O P M R E 8 2 2.2 Business Energy US ERM Power’s Houston-based energy retailing business, Source Power & Gas, serves C&I customers in the ERCOT and PJM energy markets. These markets cover Texas and 13 other states in the north east and mid-west of the country. Financial result from discontinued operations Underlying EBITDAF ($’000) Underlying NPAT ($’000) Significant items ($’000)1 Statutory NPAT ($’000) FY2018 FY2017 173 (19,283) 14,685 (4,734) (9,676) 10,654 Change 4,907 (9,607) 4,031 (33,968) (20,330) (13,638) 1 Significant items include the after tax impact of unrealised mark to market movements of financial instruments of a $6.9m gain (2017: $10.7m loss), termination costs of $3.7m in respect of exiting the businesses previous sleeving agreement, the effect of a change in federal tax rates in the US of $7.6m and the deferred tax asset write-down for non-recoverability of US tax losses of $10.3m. The prior year results include the residential business sold during FY2017. Operational performance During the year load continued to grow with 6.3 TWh sold, up 65% on the prior year when excluding the FY2017 US residential book. Operating costs of $20.5m were in line with forecast, however gross margin was below expectations at $3.28/MWh. The underlying NPAT loss for the year was $19.3m. As a result of the decision to realise future value for the business through a sale, the operating results are classified as part of discontinued operations and the respective assets and liabilities held at 30 June 2018 to be divested are classified as held for sale. Appendix A1.4 contains further details of the operating results for the year and prior years. Divestment ERM Power acquired Source in early 2015 as an entry point for ERM Power to geographically expand its successful electricity retailing model from Australia to the US. While load has grown roughly six times since that acquisition, ERM Power has decided that the US business may be of more value to a US strategic buyer while ERM Power increases its focus and allocation of capital on expanding its growing Energy Solutions business. Accordingly, a sale process was initiated in June 2018 and the Group expects to finalise a sale of the business before the end of the calendar year. Net assets held for sale at 30 June 2018 are $13.2m including the unrealised MTM value of derivative financial instruments. Investors and the market will be updated on the sale process in due course. t r o p e R l a u n n A 8 1 0 2 9 2 Operating and Financial Review SECTION 2: DIVISIONAL PERFORMANCE REVIEW 2.3 Generation ERM Power has an interest of 497 MW in two high quality power stations; Oakey and Neerabup (100% interest in the Oakey power station). ERM Power is the operator of both these power stations. Financial result $m External revenue and other income Oakey Neerabup Generation development and operations Underlying EBITDAF Oakey Neerabup Generation development and operations FY2018 FY2017 Change % 35.6 34.6 1.3 71.5 17.0 27.6 (0.8) 43.8 96.4 34.2 1.3 131.9 15.8 27.2 (1.3) 41.7 (60.8) (63%) 0.4 - 1% - (60.4) (46%) 1.2 0.4 0.5 2.1 8% 1% 38% 5% Operational highlights Neerabup Power Station had exceptional operating performance during FY2018 with availability of 99.8%. In response to favourable market conditions driven by weather and plant outages, the power station operated 8.36% of the time, compared to 5.5% in FY2017. This was well above the stations life average. Oakey Power Station’s availability was 91% in FY2018 compared to 90.86% in FY2017. The power station operated 2.5% of the time, compared to 4.5% in FY2017. The power station successfully completed the final stage of its major maintenance of the second unit in 2H FY2018. There were no Lost Time Injuries at Neerabup or Oakey Power Station during the year, continuing ERM Power’s track record of exceptional safety performance in power station operations. Financial performance Underlying EBITDAF for the period was $43.8m, up 5% on the prior year. Plant outages and a tight wholesale market in Western Australia enabled additional merchant revenue to be generated by Neerabup. The decrease in operation of the Oakey power station did not result in lower earnings due to favourable derivative hedge contracts and as a result of electing to sell gas as a more profitable option than producing electricity. Capital expenditure costs incurred during the year on the major maintenance were in line with expectations at $9.5m. R E W O P M R E 0 3 2.4 Energy Solutions ERM Power’s Energy Solutions business provides an expanding portfolio of energy solutions to our business customers. Financial result $m Revenue (including internal segment sales) Gross margin Operating expenses Underlying EBITDAF FY2018 FY2017 Change 18.9 10.6 (14.2) (3.6) 12.2 6.6 (10.9) (4.3) 6.7 4.0 (3.3) 0.7 % 55% 61% (30%) 16% Operational highlights Strong growth in the metering and advisory service units underpinned the higher revenue and gross margin results compared to the previous period. An increasing share of customers are purchasing multiple products and services as the integrated sales model offering a customised mix of energy solutions gains traction. High electricity prices continue to drive customers to seek advice and energy efficiency solutions. The business continues to develop new products and strategic partnerships to ensure it can respond to a wide range of customer needs. Financial performance Revenue grew 55% over the past year with growth particularly strong in advisory and metering services, which made up 29% of total revenue and 48% of gross margin. Expanding the sales and delivery capacity of the business was a key priority in FY2018 which led to an increase of 30% in operating costs, primarily due to an increase in staff numbers across the operating unit. 2.5 Corporate and other Financial result $m External revenue Expenses Underlying EBITDAF FY2018 FY2017 Change 0.6 (15.2) (14.6) 2.9 (15.5) (12.6) (2.3) 0.3 (2.0) % (79%) (2%) (16%) Net corporate costs increased on the prior year as a result of external software licence agreements finishing in FY2017. Gross costs decreased slightly on the prior period. t r o p e R l a u n n A 8 1 0 2 1 3 Operating and Financial Review APPENDICES Appendices A1.1 Non-IFRS Financial Information The directors believe the presentation of certain non-IFRS financial measures is useful for the users of this document as they reflect the underlying financial performance of the business. The non-IFRS financial profit measures are used by the Managing Director to review operations of the Group and include but are not limited to: 1. 2. 3. EBITDAF - Earnings before interest, tax, depreciation, amortisation, impairment and net fair value gains / losses on financial instruments designated at fair value through profit. EBITDAF excludes any profit or loss from associates. Underlying EBITDAF - EBITDAF excluding significant items. Underlying NPAT - Statutory net profit after tax attributable to equity holders of the Company after excluding the after tax effect of unrealised marked to market changes in the fair value of financial instruments, impairment and gains / losses on onerous contracts and other significant items. Underlying NPAT excludes any profit or loss from associates. All profit measures refer to continuing operations of the Group unless otherwise noted. A reconciliation of underlying NPAT and underlying EBITDAF is detailed in Appendix A1.2 of this document. The above non-IFRS financial measures have not been subject to review or audit. These non-IFRS financial measures form part of the financial measures disclosed in the books and records of the Consolidated Entity, which have been reviewed by the Group’s auditor. The Group is required to value its forward electricity purchase contracts at market prices at each reporting date. Changes in values between reporting dates are recognised as unrealised gains or losses in the particular reporting year either in profit or loss or the hedging reserve. The directors believe that underlying EBITDAF and underlying NPAT provide the most meaningful indicators of the Group’s business performance. Significant items adjusted in deriving these measures are material items of revenue or expense that are unrelated to the underlying performance of the Group. To allow shareholders to make an informed assessment of operating performance for the year, a number of significant items of revenue or expense in each year have been identified and excluded to calculate an underlying EBITDAF and underlying NPAT measure. These items may relate to one-off transactions or revenue or costs recognised during the year that are not expected to routinely occur as part of the Group’s normal operations. A reconciliation of underlying EBITDAF and underlying NPAT are shown in the tables below. A1.2 Reconciliation of underlying EBITDAF and underlying NPAT FY2018 $m Business Energy AU Generation Energy Solutions Corporate and other Group Statutory EBITDAF continuing operations Significant items Underlying EBITDAF continuing operations 71.9 - 71.9 43.8 - 43.8 (3.6) - (3.6) (14.6) - (14.6) 97.5 - 97.5 Statutory NPAT continuing operations (40.0) 10.6 (4.1) (13.2) (46.7) Significant items EBITDAF adjustments (above) SME single site impairment Tax effect of significant item adjustments Total significant items Fair value loss on financial instruments net of tax Associate gain after tax Underlying NPAT continuing operations - 1.0 (0.3) 0.7 76.2 - 36.9 - - - - 0.2 - 10.8 - - - - - - (4.1) - - - - - (0.2) (13.4) - 1.0 (0.3) 0.7 76.4 (0.2) 30.2 R E W O P M R E 2 3 FY2017 $m Business Energy AU Generation Energy Solutions Corporate and other Group Statutory EBITDAF continuing operations1 Significant items Underlying EBITDAF continuing operations1 53.4 - 53.4 41.7 - 41.7 (4.3) - (4.3) (12.6) - (12.6) 78.2 - 78.2 Statutory NPAT continuing operations1 16.8 18.8 (3.6) (12.8) 19.2 Significant items EBITDAF adjustments (above) Total significant items Fair value gain on financial instruments net of tax1 Associate loss after tax Underlying NPAT continuing operations1 1 FY2017 figures restated to exclude US operations now included within discontinued operations. A1.3 Historical figures continuing operations - - (25.4) - (8.6) - - (10.2) - 8.6 - - - - (3.6) - - - 0.3 (12.5) - - (35.6) 0.3 (16.1) $m Unless indicated FY2018 FY2017 FY2016 FY2015 FY2014 Business Energy Australia1 Load (TWh) Underlying gross margin Underlying operating expenses Underlying gross margin $ per MWh Underlying operating expenses $ per MWh Underlying EBITDAF Generation1 Oakey Neerabup Generation development and operations Underlying EBITDAF Corporate division statistics1 Total revenue Total expenses Underlying EBITDAF Energy Solutions1 Revenue (includes internal segment sales) Gross margin Operating expenses Underlying EBITDAF 1 Excluding significant items – refer to A1.2 for further details. 19.2 93.9 (22.0) 4.90 (1.15) 71.9 17.0 27.6 (0.8) 43.8 0.6 (15.2) (14.6) 18.9 10.6 (14.2) (3.6) 18.5 76.0 (22.7) 4.11 (1.23) 53.4 15.8 27.2 (1.3) 41.7 2.9 (15.5) (12.6) 12.2 6.6 (10.9) (4.3) 18.1 76.0 (20.6) 4.20 (1.14) 55.4 11.5 25.1 (1.2) 35.4 1.5 (13.1) (11.6) 5.1 2.8 (4.1) (1.3) 16.1 76.1 (21.5) 4.72 (1.34) 54.6 22.7 25.2 (1.1) 46.8 2.7 (16.6) (13.9) - - - - 14.1 59.1 (17.9) 4.20 (1.27) 41.3 28.6 23.1 (1.2) 50.5 1.6 (16.0) (14.4) - - - - t r o p e R l a u n n A 8 1 0 2 3 3 Operating and Financial Review APPENDICES A1.4 Business Energy historical margins1 Underlying gross margin $/ MW 2H FY2018 1H FY2018 2H FY2017 1H FY2017 2H FY2016 1H FY2016 Australia US – discontinued operations Underlying Opex $/MWh Australia US – discontinued operations Load sold (TWh) C&I Australia SME Australia US – discontinued operations Underlying EBITDAF ($’000) Australia US – discontinued operations 4.72 2.83 5.08 3.78 7.24 2.92 0.73 4.23 3.93 7.16 4.49 5.61 (1.15) (3.22) (1.15) (3.30) (1.26) (4.36) (1.19) (4.70) (1.08) (6.13) (1.21) (6.82) 9.3 0.3 3.3 9.2 0.4 3.0 9.2 0.4 2.6 8.5 0.4 2.0 8.8 0.3 1.3 8.7 0.3 1.1 34,177 (1,274) 37,733 1,447 57,437 (3,783) (4,078) (951) 25,970 1,276 29,450 (1,283) 1 All comparative figures for the US discontinued operations include earnings for the residential business, which was sold during FY2017. R E W O P M R E 4 3 Glossary $m C&I Millions of dollars Commercial and Industrial Contestable Revenue Contestable revenue is the electricity sales revenue component on which we earn a margin and excludes pass-through items such as network charges EBITDAF EBIT ERCOT 1H 2H FY GWh IFRS MWh NEM NPAT PJM Sleeving SME Earnings before interest, tax, depreciation, amortisation, impairment and net fair value gains / losses on financial instruments designated at fair value through profit and loss. EBITDAF excludes any profit or loss from associates Earnings before interest and tax Electric Reliability Council of Texas First half of financial year Second half of financial year Financial year ended or ending 30 June Gigawatt hours is a unit of energy representing one billion watt hours International Financial Reporting Standards Megawatt hours is a unit of energy representing one million watt hours The National Electricity Market Net profit after tax Pennsylvania, Jersey, Maryland Power Pool Credit sleeving through intermediary to trade and hedge with third parties Small to Medium Enterprise Source Power & Gas SPG Energy Group LLC TWh Terawatt hours is a unit of energy representing one thousand gigawatt hours (GWh) UMI Survey Utility Market Intelligence (UMI) survey of major retail electricity retailers by independent research company NTF Group in 2017. Research based on survey of 300 business electricity customers between November 2017 and January 2018. Three major electricity retailers benchmarked Underlying EBITDAF EBITDAF excluding significant items Underlying EBIT Underlying NPAT EBIT after excluding the unrealised marked to market changes in the fair value of financial instruments, impairment and gains / losses on onerous contracts and other significant items. Underlying EBIT excludes any profit or loss from associates Statutory net profit after tax attributable to equity holders of the Company after excluding the after tax effect of unrealised marked to market changes in the fair value of financial instruments, impairment and gains / losses on onerous contracts and other significant items. Underlying NPAT excludes any profit or loss from associates US or USA United States of America t r o p e R l a u n n A 8 1 0 2 5 3 Corporate Social Responsibility For the year ended 30 June 2018 1. LEADERSHIP Approach ERM Power has demonstrated industry leadership in a year of complex and dynamic policy challenges. With 22% share (by load) of the Australian business electricity market and market-leading customer satisfaction, the Company’s credibility in public policy is founded on customer advocacy and insights, deep knowledge of industry processes, diverse business interests and a direct approach. Operating in this highly regulated sector, anticipating and influencing public policy is critical to successful business strategy development and execution. ERM Power executives and regulatory specialists actively participate in advocacy and government relations opportunities, sitting on various consultative forums, writing regulatory submissions and engaging with strategic stakeholders. ERM Power also utilises peak bodies, including the Australian Industry Group and the Energy Efficiency Council to amplify its voice across the sector. Policy environment in 2018 Over the past year energy policy debate continued to dominate the sector and public discourse. The need for enduring, bipartisan national energy policy has never been greater though politics continues to overshadow policy. The transition to renewables and new technology is challenging but ERM Power remains committed to supporting development of policy which eases the transition for the benefit of customers and the community. In the absence of a clear policy framework around energy and climate targets, ERM Power’s role in helping customers manage volatility and energy productivity has never been more important. ERM Power’s key policy principles Whether discussing day-to-day obligations or the sector’s future more broadly, ERM Power maintains a strong principled approach to advocacy. Priority principles are: • • • • Enduring, bipartisan, national energy policy, to support greater investment certainty; An efficient and orderly transition to a low-emissions energy sector, recognising gas-fired electricity generation as a vital support to intermittent renewables; Competitive and technology neutral policies, to provide an even playing field to meet sectoral objectives; and Supporting both supply and demand-side measures to improve market efficiency and reliability at lowest cost, to support customers. These are integral to creating a sustainable energy market into the future. 2. CUSTOMERS ERM Power is an energy business for business. The Company makes it simple for organisations to take charge of their energy and make smarter choices. ERM Power continues to demonstrate outstanding service for its customers. In Australia, the Utility Market Intelligence survey1 reported 92% satisfaction from ERM Power’s large business customers, and yet again ranked No.1 in customer satisfaction against its peers. This marks the seventh consecutive year that ERM Power has dominated other retailers in this survey. Broker satisfaction in Australia is similarly impressive with industry leading satisfaction and a No.1 ranking against other retailers as shown in the Markets and Communication Research (MCR) survey2. Momentum in delivering strong service also continues in the US, with Source Power and Gas’s broker satisfaction ranking being in the top three for the third consecutive year. This is a survey3 of more than 140 brokers ranking more than 50 retailers. At the same time the recognition rate has nearly tripled since acquisition in 2015 going from 21% to 62% of surveyed brokers saying they do business with Source. 3. WORKPLACE Employee engagement and enablement ERM Power listens to what employees have to say about their workplace. Based on results from ERM Power’s second formal employee engagement and enablement survey in 2017, it was clear that employees felt both highly engaged and enabled to strive for results on behalf of the organisation whilst reaching their potential. ERM Power rated at or above global high-performing norms in a number of critical areas including employee engagement, employee enablement, confidence in leadership, clarity of business strategic direction and customer focus. Since the survey, strong emphasis has been placed on further improving the workplace experience, with learning and development and collaboration selected as priority areas of focus. A number of organisational-wide initiatives have been implemented to enhance these priorities, including development programs at all levels and a hackathon. The hackathon brought together multi- disciplinary teams who applied design thinking to come up with proposed solutions to a range of business challenges. Improvement in both learning and development and collaboration together with other key areas is evident through results from short, regular staff surveys. These internally administered surveys provide an interim indicator of progress ahead of the next formal employee engagement and enablement survey in 2019. Supporting staff wellness Maintaining a healthy workforce by supporting employee wellbeing has positive outcomes for both employees and ERM Power. ERM Power offer a range of workplace programs, policies and facilities to support personal wellness. A key initiative offered during the year was a targeted wellness program which provided employees the tools and knowledge to promote balance across key life domains including relationships, nutrition, sleep and exercise. Other initiatives include a recently updated flexible working policy, an Employee Assistance Program and workplace health and safety training and awareness sessions on a broad range of topics including workplace behaviour, mental health and ergonomics. 1 Utility Market Intelligence survey of large customers of major electricity retailers by independent research company NTF Group from 2011 – 2017 2 Market and Communication Research (MCR), February 2018 3 Energy Research Consulting Group’s (ERCG) survey, January 2018 R E W O P M R E 6 3 Safety Safety is the top priority across ERM Power’s locations. Safety measures are reported at each Board meeting, including any first-aid treatment, near misses, and lost-time injuries. Safety is the first Key Performance Indicator (KPI) for all power station personnel. On-site staff participate in regular safety briefings, plan job observations, safety procedure reviews, and drug and alcohol testing. All corporate staff complete regular online Workplace Health and Safety training modules, and participate in monthly briefings. 4. COMMUNITY ERM Power actively seeks to engage with and give back to the communities in which it operates. In 2017, ERM Power launched its ‘Power of Giving’ sponsorship program as a formal channel for community support and engagement, and continues to honour that program by supporting a wide array of charitable causes throughout the country. Staff are also encouraged to utilise volunteer leave to support charitable causes. Initiatives supported by ERM Power staff in FY2018 include: In FY2018 ERM Power again celebrated an excellent safety record. Across both Neerabup and Oakey power stations, there were no lost-time injuries, including during Oakey’s second major gas turbine and generator overhaul, and a full station upgrade of the operating control system on both gas turbines and the balance of the plant. Diversity Research shows that organisations comprising of an employee base with a broad range of experience and attributes in a workplace environment that encourages diversity of thought make better decisions and ultimately produce stronger results. Board and employee diversity is the responsibility of the Remuneration & Nomination Committee and is a focus for the executive and leadership team. ERM Power continues to make positive progress towards its diversity targets set by the Board in 2016 and has since added additional internal targets which are reviewed monthly at the executive level. Recognising that leadership starts at the top of an organisation, on 28 February 2018 ERM Power announced the appointment of independent non-executive director Julieanne Alroe, to commence in August 2018. Julieanne is a highly experienced executive with exceptional business leadership qualities and experience in strategy, risk and governance across a range of industries. With Julieanne joining Georganne Hodges as a director, the representation of women on the Board has increased to 25%. ERM Power continues to improve workplace diversity through a range of initiatives and policies, including: • • • • • • • Attraction strategies that focus on target labour market segments; Annual gender pay equity reviews to proactively address gender pay gaps; Ensuring team diversity is considered throughout the recruitment and promotion process; Paid parental leave entitlements; Flexible work arrangements; Women in leadership program; and Formal talent identification and succession planning. ERM Power’s report for the Workplace Gender Equality Agency is a comprehensive review of gender diversity in ERM Power’s Australian workforce. The 2018 report shows continued progress from the previous reporting period, and is available on the website, along with the company-wide Gender Diversity Policy. • • • • • Over $72,000 raised through the Vinnies CEO Sleepout event in Brisbane. In addition to participating each year, CEO Jon Stretch is also a CEO Sleepout ambassador, helping to raise awareness for the issue of homelessness while encouraging his peers to participate. ERM Power became a sponsor for Robogals Brisbane – an international student-run organisation that aims to inspire, engage and empower young women to consider studying engineering and related fields. The team at Neerabup Power Station threw its support behind the Black Dog Institute to help heighten awareness of important mental health issues. The Neerabup Power Station team also took advantage of ERM Power’s volunteer entitlement to support Manna Inc. – a charitable organisation that aims to provide hope and dignity to Perth’s hungry and under privileged. The team prepared 160 meals for those in need. ERM Power continues its long-term support of indigenous education programs at The Armidale School in New South Wales and Geelong Grammar School in Victoria. 5. ENVIRONMENT As a diversified energy company, ERM Power recognises the potential for its business to both burden and protect the natural environment. This influences how the Company runs its business, as well as the products and services offered to customers. Power station environmental compliance As operators at Oakey and Neerabup power stations, ERM Power is responsible for ensuring compliance with environmental license conditions. The Company regularly monitors and reports on a broad range of environmental factors, including air and water quality, waste management, emissions of greenhouse gases and other pollutants, pest control, and chemical use. During FY2018 there were no reportable environmental incidents, nor were there any breaches of any environmental licence conditions at either plant. t r o p e R l a u n n A 8 1 0 2 7 3 Corporate Social Responsibility For the year ended 30 June 2018 FY2018 Environmental snapshot Power Station Generation (GWh) Scope 1 Emissions (tCO2-e) Environmental incidents Water discharge strategy Oakey Power Station 73.9 47,187 Neerabup Power Station 250.5 155,772 Nil Nil Discharge reused for farmland irrigation (salinity neutralised if required). Nil discharge – waste water is evaporated to brine. As peaking power stations, operation and output varies significantly each year as the Company responds to market signals. Accordingly, greenhouse gas emissions from the power stations can also vary significantly. ERM Power maintains high efficiency standards to manage both operational and environmental impact. ERM Power continually looks for ways to become more efficient and effective in its operations. For example, during the year the water treatment plant at Oakey power station was upgraded, increasing overall water production efficiency. Supporting renewable energy ERM Power is committed to playing its part in the transition to a less emission-intensive energy sector. The Renewable Energy Target requires electricity retailers like ERM Power to acquire regulatory certificates from renewable energy generators. Retailers may achieve compliance under the scheme by either surrendering the required number of certificates to the Clean Energy Regulator, or by paying a charge for the shortfall in surrendered certificates. Scheme legislation provides a three-year window whereby a retailer may surrender certificates and receive a refund for any charge previously paid. For the 2017 compliance year, ERM Power achieved compliance by surrendering 2.652m large scale generation certificates (LGCs). ERM chose to surrender certificates to cover the entire 2017 compliance year liability and there was no shortfall charge payable. Energy Solutions ERM Power considers it both a business opportunity and a social responsibility to enable customers to lower their carbon footprint through smarter energy usage. The Company helps customers meet their environmental commitments by offering Government-accredited renewable energy under the GreenPower Program. This allows customers to make voluntary contributions above and beyond what otherwise would have occurred. With its growing Energy Solutions portfolio, ERM Power makes it simple for organisations to take charge of their energy and make smarter choices. The Company relieves organisations of the stress of energy management – cutting through the complexity to develop tailored solutions and help them achieve better energy and business outcomes. When businesses take charge of their energy needs they save time and money, and can remain focused on their business. 6. RISK FRAMEWORK AND MANAGEMENT Group risks ERM Power recognises that risk is an inherent part of its business. Risk arises from both the external environment in which the Company operates, and its own business and investment decisions. ERM Power does not seek to eliminate these risks; rather it looks to manage and mitigate them, and use them to create opportunity, ensuring the potential range of outcomes is acceptable. Risk management framework Effective risk management requires that risk assessment and decision making is introduced into all functions of the business and through all stages of decision making, whether it be strategy, planning, delivery of projects or operation of assets. All ERM Power staff are responsible for, and empowered to, take ownership of risk management within their function and for their level of responsibility. This organisation-wide adoption of risk management principles and practices is encouraged and promoted by the ERM Power Board and the executive team. Final accountability and authority for the Risk Management Framework Policy and decisions rests with the Board. Ultimate responsibility Delegated authority / responsibility ERM Board Executive Team Audit and risk committee Enterprise risk committee Business Managers Divisional risk management ERM Power’s Risk Management Framework Policy is publicly available on the Company’s website: https://ermpower.com.au/about-erm/ corporate-governance/ See the ERM Power Corporate Governance Statement at https://ermpower.com.au/investors-media/reports-presentations/ R E W O P M R E 8 3 Material business risks ERM Power has an Enterprise Risk Committee which reviews on a quarterly basis business risks, potential impacts and mitigation programs. Key business risks are summarised in no particular order of significance as follows: Risk Potential Impacts Mitigation Industry risk An evolving industry structure, highly competitive retail environment and technological changes in the generation and delivery of energy pose risks and opportunities for the business model. · The business model includes diversification of service and product offerings and geography of operations. · The business generates revenue on both the supply and demand side. · A focus on superior quality of service offering includes deep retailer broker and customer relationships, data services and bespoke product offerings. · The business model allows for incorporating commercial opportunities arising from an evolving industry. Regulatory changes Commodity price Liquidity in energy derivative markets System failures and cyber risk Government policy and regulatory changes create investment and price uncertainty and can result in restrictions or changes to product and service offerings and price structures. · ERM Power has a strong voice in the industry and responds to the regulatory environment via written submissions, participation on industry groups and by representation to regulators, policy makers and politicians, thus influencing outcomes. · Strategy supports new and strategic commercial opportunities which leverage regulatory and policy change. ERM Power is exposed to fluctuations in wholesale market electricity and renewable energy certificate prices. This can increase cost of procuring energy to meet customer contract requirements. Lack of liquidity in the energy derivative market can impact accurate pricing of r etail contracts and hedging of retail contracted load. A failure of our system infrastructure or a cyber-security event may lead to a disruption of operations, a privacy breach, data corruption, theft of commercially sensitive information and damage to our reputation. · Group policies prescribe active management of exposures arising from forecast electricity sales within prescribed limits. In doing so, various hedging contracts have been entered into with individual market participants. · The hedging program includes severe weather event mitigation. · The Group employs a diverse and dynamic trading strategy which is highly responsive to market dynamics. · ERM Power forms strategic trading relationships with energy generators. · The Group undertakes system reliability measures which include maintenance and systems support. · The Group’s approach to cyber security leverages industry best practice set out in Information Security Management standards. Power station failure Prolonged outage of Oakey or Neerabup Power Stations would lead to a loss of revenue, coinciding with a potentially high cost of servicing derivative hedges. · The Group undertakes a preventive maintenance program. · Has established contingency plans. · Employs fire protection systems and flood plans. · Has security systems to prevent security breaches. · Has an excellent availability record based on maintenance and training. Credit risk ERM Power could suffer financial losses if a debtor or wholesale counterparty fails to meet contractual obligations. Funding risk A failure to secure or maintain funding would negatively impact on financial performance, business strategies and growth plans. Talent management and succession planning An inability to attract and retain talent could impact the Company’s future financial performance, as well as hinder the ability to innovate. The Group seeks to limit its exposure to credit risks by: · conducting appropriate due diligence on counterparties before entering into arrangements with them; · where appropriate obtaining collateral with a value in excess of the counterparties’ obligations to the Group; · preferential contracting with high credit quality derivative counterparties; · diversification by reducing reliance on particular counterparties; · reporting and monitoring credit exposures on a regular basis; and · setting credit limits aligned to assessed credit strength. · Actively consider the level of funding under the Group’s capital management framework. · Maintain existing diversified funding sources and relationships. · The Company has a robust HR framework in place which includes leadership development and succession planning, career pathway support, a learning and development programme, a focus on engagement and enablement and a competitive remuneration program. · An LTI scheme is in place for executives, which encourages retention as well as high performance. Fraud Fraud or ethical misconduct could damage our reputation, adversely affect operations and result in financial loss. · Regular risk assessments and internal control processes. · Pre-employment screening. · Segregation of duties. · Regular review of financial delegations. · Fraud awareness training for all staff. t r o p e R l a u n n A 8 1 0 2 9 3 Directors’ Report For the year ended 30 June 2018 Directors’ Report In accordance with the Corporations Act 2001, the directors of ERM Power Limited (“Company”) report on the Company and the consolidated entity ERM Power Group (“Group”), being the Company and its controlled entities, for the year ended 30 June 2018 (“the year”). The information appearing on the preceding pages forms part of this Director’s Report. 7. LIKELY DEVELOPMENTS AND EXPECTED RESULTS Apart from the matters referred to in the Operating and Financial Review on pages 19 to 35, information as to other likely developments in the operations of the Group and the expected results of those operations in subsequent financial years has not been included in this report because the directors believe this could result in unreasonable prejudice to the Group. 1. PRINCIPAL ACTIVITIES The principal activities of the Group during the year were: • • • electricity sales to businesses in Australia and the United States of America; generation of electricity; and energy solutions. 2. OPERATING RESULTS FOR THE YEAR A review of the operating results of the Group can be found in the Operating and Financial Review on pages 19 to 35. 3. REVIEW OF OPERATIONS A review of the operations of the Group can be found in the Operating and Financial Review on pages 19 to 35. 4. BUSINESS STRATEGIES AND PROSPECTS A review of the business strategies and prospects of the Group can be found in the Operating and Financial Review on pages 19 to 35. 5. SIGNIFICANT CHANGES IN THE STATE OF AFFAIRS Consistent with the Company’s capital management framework, on 22 February 2018 the Company announced an on-market share buy- back of up to $20 million. The buy-back commenced in March 2018. On 29 June 2018, the Company signed a contract for the sale of our SME single site book, which comprises about 5,200 sites. As at 30 June 2018, the Group has classified $3.4m intangible assets and $1.5m liabilities as held for sale and impaired $1.0m of SME single site customer acquisition costs held for sale to reflect management’s decision to sell the single site SME customer contracts from the Business Energy Australia operations. In June 2018, a sale process of the US business was initiated and the Group expects to finalise a sale of the business before the end of the 2018 calendar year. At this stage of the sale process, expected sale proceeds are unknown. As a result of the decision to realise future value for the business through a sale, the operating results are classified as part of discontinued operations and the respective assets and liabilities held at 30 June 2018 to be divested are classified as held for sale. 6. EVENTS AFTER BALANCE DATE Since 30 June 2018 there have been no other matters or circumstances not otherwise dealt with in the Financial Report that have significantly or may significantly affect the Group. 8. PROCEEDINGS ON BEHALF OF THE COMPANY No person has brought or intervened in on behalf of the Company with an application for leave under section 237 of the Corporations Act 2001. 9. DIVIDENDS Subsequent to year end, the directors have declared a final dividend in respect of the 2018 financial year as follows: Amount: Franking: 4.0 cents per share 100% franked Date Payable: 10 October 2018 The dividend has not been provided for in the 2018 financial statements. During the year the Company paid an interim fully franked dividend of 3.5 cents per share (2017: 3.5 cents fully franked), together with a fully franked final dividend of 3.5 cents per share in respect of the previous year. 10. DIRECTORS The following persons were directors of the Company during the whole of the financial year and up to the date of this report unless otherwise indicated: Anthony (Tony) Bellas Independent Non-Executive Chair Albert Goller Independent Non-Executive Director Georganne Hodges Independent Non-Executive Director Antonino (Tony) Iannello Independent Non-Executive Director Philip St Baker Trevor St Baker Non-Executive Director (appointed 14 July 2017) Non-Executive Deputy Chair and Founder (resigned 14 July 2017) Wayne St Baker Non-Executive Director Jonathan (Jon) Stretch Managing Director and Chief Executive Officer (MD & CEO) Information on the current directors can be found in the Board of Directors section on pages 10 to 13. This information includes the qualifications, experience, other directorships and special responsibilities of each director in office as at the date of this report. R E W O P M R E 0 4 11. MEETINGS OF DIRECTORS Board meetings Audit & Risk Remuneration & Nomination A 15 15 13 14 11 2 14 15 B 15 15 15 15 13 2 15 15 A 6 6 6 6 ** ** ** ** B 6 6 6 6 ** ** ** ** A 6 6 ** 6 6 ** ** ** B 6 6 ** 6 6 ** ** ** Tony Bellas Albert Goller Georganne Hodges Tony Iannello Philip St Baker Trevor St Baker Wayne St Baker Jon Stretch A = number of meetings attended B = number of meetings held during the time the director held office during the year ** = Not a member of the relevant committee 12. DIRECTORS’ INTERESTS The relevant interest of each director in the share capital of the Company at the date of this report, as notified by directors to the ASX in accordance with Section 205G of the Corporations Act, is as follows: Tony Bellas Albert Goller Georganne Hodges Tony Iannello Philip St Baker Wayne St Baker Jon Stretch 13. COMPANY SECRETARIES Phil Davis LLB, AGIA Ordinary shares 106,250 290,000 - 202,839 4,762,695 1,625,290 3,132,877 Phil Davis joined ERM Power in December 2007 and was appointed Group General Counsel and Company Secretary in October 2015. During this time his roles and responsibilities have covered the whole of ERM Power’s business including generation, sales, gas activities, compliance and corporate governance. Phil is a qualified lawyer in Australia and the United Kingdom, and specialises in the corporate, construction, property, energy and resource sectors. Suzanne Irwin B.Com, CPA, C.Dec, FGIA & FCIS Suzanne Irwin joined ERM Power in February 2007 and was appointed as an additional Company Secretary in 25 August 2017 managing the administrative functions for the Corporate Secretariat department. t r o p e R l a u n n A 8 1 0 2 1 4 18. ROUNDING OF AMOUNTS The amounts contained in this report and in the financial report have been rounded to the nearest thousand dollars (where rounding is applicable) under the option available to the Group and the Company under ASIC Corporations (Rounding in Financial/Directors’ Reports) Instrument 2016/191. The Group and the Company are entities to which the instrument applies. 19. REMUNERATION REPORT The Remuneration Report is attached and forms part of this report. This report is made in accordance with a resolution of the Board of directors. Tony Bellas Chairman 23 August 2018 Directors’ Report For the year ended 30 June 2018 14. ENVIRONMENT REGULATION AND PERFORMANCE The Group’s environmental regulation and performance can be found in the Corporate Social Responsibility Report on pages 36 to 39. 15. INDEMNIFICATION AND INSURANCE OF OFFICERS Insurance and indemnity arrangements are in place for directors and officers of the Group. Disclosure of premiums and coverage is not permitted by the contract of insurance. To the extent permitted by law, the Group indemnifies every person who is or has been an officer against: • • any liability to any person (other than the Company, related entities or a major shareholder) incurred whilst acting in that capacity and in good faith; and costs and expenses incurred by that person in that capacity in successfully defending legal proceedings and ancillary matters. For this purpose, “officer” means any company secretary or any person who makes or participates in making decisions that affect the whole, or a substantial part of the business of the Company or Group. 16. AUDITOR’S INDEPENDENCE DECLARATION A copy of the auditor’s independence declaration as required under section 307C of the Corporations Act 2001 is included in the Annual Financial Statements which accompany this report. 17. NON AUDIT SERVICES Non-audit services provided by the Group’s auditors PricewaterhouseCoopers were in relation to advice and certain agreed upon procedures. The directors are satisfied that the provision of non-audit services is compatible with the general standard of independence for auditors imposed by the Corporations Act 2001. Amounts received or due and receivable by PricewaterhouseCoopers Australia for non-audit services: Other procedures in relation to the entity and any other entity in the consolidated Group 2018 2017 - $93,328 R E W O P M R E 2 4 Remuneration Report For the year ended 30 June 2018 Remuneration Report The directors present the Remuneration Report for ERM Power Limited (“Company”) and its consolidated entities (“Group”) for the year ended 30 June 2018. Structure of this report The Remuneration Report is divided into the following sections: 1. 2. 3. 4. Key Management Personnel Remuneration governance Senior executive remuneration framework FY2018 executive remuneration outcomes and the link to company performance 5. Non-executive directors’ fees 6. 7. Tables for executive remuneration and equity grants Other remuneration disclosures 1. KEY MANAGEMENT PERSONNEL For the purpose of this report Key Management Personnel (KMP) are those persons having authority and responsibility for planning, directing and controlling the activities of the Group, directly or indirectly. They include all non-executive directors of the Board in addition to the following senior executives: Jonathan (Jon) Stretch Managing Director and Chief Executive Officer (MD & CEO) William (Mitch) Anderson Executive General Manager (EGM) Business Energy (US) Gregg Buskey EGM Corporate Finance & Strategy David Guiver EGM Trading Megan Houghton EGM Energy Solutions Derek McKay Chief Information Officer (CIO) and EGM Generation Stephen (Steve) Rogers EGM Energy Retail (AU) Alastair (James) Spence Chief Financial Officer (CFO) There have been no changes to KMP from the end of the reporting period up to the date of this Remuneration Report. 2. REMUNERATION GOVERNANCE The Remuneration & Nomination Committee (Committee) ensures that the remuneration of directors and senior executives is consistent with market practice and is sufficient to ensure that the Company can attract, develop and retain the best individuals. The Committee reviews the remuneration of the MD & CEO and senior executives against the market, and against Group and individual performance. It also reviews non-executive directors’ fees against the market, with due regard to responsibilities and demands on time. The Committee oversees governance procedures and policy on remuneration including: • • • • general remuneration practices; performance management; equity plans and incentive schemes; and recruitment and termination. Through the Committee, the Board ensures that the Group’s remuneration philosophy and strategy continues to be focused to: • • • attract, develop and retain first class director and executive talent; create a high performance culture by driving and rewarding executives for achievement of the Group’s strategy and business objectives; and link incentives to the creation of shareholder value. In undertaking its role, the Committee may seek the advice of external remuneration consultants who provide analysis to ensure remuneration levels are set to reflect the market for comparable roles. In reviewing remuneration levels for FY2018, the Committee referred to a benchmarking analysis conducted by Korn Ferry Hay Group Pty Ltd (KFHG) in May 2017. Whilst KFHG did not act as a Remuneration Consultant for the purposes of the Corporations Amendment (Improving Accountability on Director and Executive Remuneration) Act 2011, it did provide benchmarking information and data to provide a frame of reference against which the committee could evaluate current remuneration levels for non-executive directors, the MD & CEO, and those executives reporting to the MD & CEO. As no “remuneration recommendations” were made, there is no requirement for KFHG to provide a declaration regarding no undue influence by members of the KMP to whom the reports related to. 3. SENIOR EXECUTIVE REMUNERATION FRAMEWORK The objective of the Company’s executive remuneration framework is to ensure that reward for performance is competitive and appropriate for the results delivered. The framework aligns executive remuneration with the achievement of strategic objectives and the creation of value for shareholders, and conforms to market practice. The Board ensures that executive reward satisfies the following key criteria for good governance practices: • • • • competitiveness and reasonableness; acceptability to shareholders; performance linkage/alignment of executive remuneration; and transparency. Remuneration and other terms of employment for the MD & CEO and the other senior executives are formalised in service agreements. Each of these agreements specifies the components of remuneration to which they are entitled and outlines base salary, the provision of incentives, other benefits including superannuation, salary continuance insurance and notice periods required on termination. Senior executives are remunerated by way of a mix of fixed and variable remuneration in a manner that motivates them to pursue the long term growth and success of the Group. The components of remuneration are: • • • base pay and benefits, including superannuation for Australian employees, or retirement contributions for US employees; short term and long term incentives; and other discretionary cash or equity based incentives. t r o p e R l a u n n A 8 1 0 2 3 4 Remuneration Report For the year ended 30 June 2018 In accordance with the objective of ensuring that executive remuneration is aligned to Group performance without encouraging undue risk taking, a significant portion of executive’s target pay is at risk. The Board considers this combination an effective way to align incentives to shareholder value (refer section 3.2). Short term incentives (STIs) are focused on achieving annual profit and operational targets, whilst long term incentives (LTIs) are focused on alignment with growth in shareholder returns assessed over a three-year period, as well as encouraging talent retention. 3.1 Base salary and benefits Remuneration is reviewed annually and external remuneration consultants are engaged periodically to provide analysis and advice to ensure executive remuneration is set at levels that reflect the market for comparable positions. The remuneration target is for a fixed remuneration level around the midpoint and a total remuneration close to or above the 75th percentile of comparator groups on achieving strong performance, with flexibility to take into account capability, experience and value to the organisation and performance of the individual. Remuneration is also reviewed on promotion or change of role. There are no guaranteed base salary increases included in executive service agreements. For Australian employees, superannuation is included in fixed remuneration up to the maximum superannuation contribution base set by the relevant legislation, while the Company contributes to the basic safe harbor 401K retirement plan for the Group’s US employees. 3.2 Incentive schemes Variable remuneration is in the form of STIs and LTIs which represent “at risk” remuneration. STIs are generally paid annually against agreed Key Performance Indicators (KPIs) which are focused on achieving profit and operational targets set by the Board annually. LTIs are designed to align the interests of the senior executives with the Company’s shareholders, being accrued over a three-year period and earned through satisfaction of both performance and service conditions. STIs are paid in the form of cash or equity, or a combination of these. LTIs are paid in the form of equity. The trading of equities which vest under incentive schemes is required to comply with the Company’s Securities Trading Policy. This policy prohibits any employees or directors from entering into any scheme, arrangement or agreement under which the economic benefit derived by the employee or director, in relation to an equity– based incentive award or grant made by the Company is altered, irrespective of the outcome under that incentive award or grant, other than as permitted in any approved share or option plan, or as authorised by the Board. For shareholders, benefits associated with the incentive schemes include: • • • focus on performance improvement at all levels of the Group, with year-on-year earnings growth a core component; focus on sustained growth in shareholder wealth, consisting of share price growth, and delivering the greatest returns on assets; and the ability to attract and retain high calibre executives. For employees, benefits associated with the incentive schemes include: • provision of clear targets, stretch targets and structures for achieving rewards; recognition and reward for achievement, capability and experience; and delivery of reward for contribution to growth in shareholder wealth. • • R E W O P M R E 4 4 KPIs for STI include both financial and non-financial measures using a balanced scorecard approach, and reflect the key measures of success as determined by the Board. These vary from year to year and may include, but are not limited to, a range of measures such as: • • • financial measures – including underlying net profit after tax (underlying NPAT), underlying earnings before interest, tax, depreciation, amortisation, impairment and net fair value gains/losses on financial instruments designated at fair value through profit and loss, excluding significant items (underlying EBITDAF), a cash flow proxy, load, etc.; people, engagement and enablement measures – safety and environment performance measures, including lost time injury frequency rates, medically treated injury frequency rates and environmental measures; and strategic imperatives – focusing on major specific project goals for the period. KPIs for LTI are market based – with total shareholder return (TSR) quantitative measures. Malus and Clawback The Company has malus and clawback provisions whereby awards will lapse, be forfeit or a participant may be required to reimburse the Company all or part of the cash received as net proceeds on the sale of any award if, in the opinion of the Board: • • • a participant is found to have acted fraudulently or dishonestly or is in material breach of obligations to the Group; the Company becomes aware of a material misstatement or omission in the financial statements in relation to the Group; or any circumstances occur that the Board determines in good faith to have resulted in an unfair benefit to the participant. 3.2.1 Short term incentives STIs are provided to most employees. The awarding of STIs is based on performance against KPIs or targets across three components; individual, team and corporate. Each of these components is allocated a weighting and include both targets and stretch targets that are set at the beginning of each financial year. The MD & CEO’s targets and the corporate targets are set by the Board, whilst the individual and team targets are set under the direction of the MD & CEO. The Committee is responsible for determining the STI to be awarded based on an assessment of whether the KPIs are met. To assist in this assessment, the Committee receives detailed reports on performance from management. The Committee has the discretion to not award and to adjust STIs downwards in light of unexpected or unintended circumstances. At the end of each financial year, achievement of targets is measured and applied against the target participation rate determined for each individual. These participation rates range between 10% and 40% of annual average base salary, with the potential to achieve up to 150% of these levels (i.e. 15% to 60%) for employees other than the MD & CEO and CFO, whose maximum participation rate for the FY2018 STI was 150% and 112.5% respectively. STI awards may be offered by way of cash and/or equity at the election of the Board. Any equity award normally vests immediately. The following apply to STI in the event of cessation of employment: • • Termination (without cause) - entitlement to pro rata STI for the year is subject to Board discretion. Termination (with cause) - STI is not awarded. 3.2.2 Long term incentives The provision of LTI awards exposes executive KMP to long-term movements in the price of the Company’s shares, by aligning the long-term interests of executives with shareholders through the use of a Total Shareholder Return (TSR) performance hurdle. This reflects the Company’s strategy of adopting a long-term approach to decision making and sustained value creation for shareholders. For Australian employees, up to and including FY2018 LTIs were provided to selected employees in the form of units in the Company’s Employee Share Trust (EST) as established in 2010. The corresponding equity is issued into the EST and units may vest subject to satisfaction of performance and service conditions. During the vesting period, the units are held beneficially on behalf of the participants, and thus the participant enjoys many of the same benefits as the holder of ordinary shares; with entitlement to any dividends that may be awarded and the right to direct the trustee as to how to cast their vote at a meeting of members, although participants are not eligible for the Dividend Reinvestment Plan. These benefits formed part of the employees’ total remuneration package and are taken into account during annual remuneration reviews. From FY2019 Australian LTI will be awarded by way of Performance Rights which do not carry voting rights nor will they have any entitlement to dividends. For US employees, a “Phantom Equity Plan” emulates, as much as possible, the Australian LTI plan, however no equity is actually issued. US participants are given an award of “phantom shares”, based on the relevant ASX:EPW market value of shares as at the grant date. The number of phantom shares will convert to a cash salary payment after the expiry of the performance period at which time the value to be paid is determined based on the market value of shares at the end of the performance period, with the same performance and service criteria as Australian participants. No dividends, dividend equivalent cash salary payments or voting rights are associated with the phantom shares. Early vesting may occur on a change of control of the Company or the Company’s US business, as relevant. A change of control for the Company is determined as a material change in the composition of the Board initiated as a result of a change of ownership of shares and the purchaser of the shares requiring (or agreeing with other shareholders to require) that change in Board composition, or in other circumstances that the Board determines appropriate. The following will apply to unvested LTI awards on termination of employment: Circumstance Potential benefit/treatment Death, serious injury, disability or serious illness that results in the employee leaving ERM Power “early”. All LTI will vest. Resignation or termination for cause. All LTI will be forfeit. Redundancy, retirement or termination by mutual agreement. The Board will determine if the unvested LTI will continue to be held from the date the participant’s employment ceases to the date at which the relevant LTI award vesting is determined, subject to any other vesting conditions (and subject to limits outlined in the Corporations Act 2001 as they relate to Termination Payments). LTI issues made in the reporting period will vest subject to continuation of employment for the three-year performance period and total TSR performance. The TSR vesting condition will be determined by the Company’s relative TSR performance over the three-year period commencing 1 July, measured against the TSR performance of a comparator group being those companies in the Standard & Poor’s (S&P) ASX 300 index at the beginning of the performance period. At the end of the three-year period, vesting is determined on the following basis: • • • Less than or equal to 50th percentile = 0% Greater than 50th to less than the 75th percentile = 50% to 100% (linear) 75th percentile and higher = 100%. The performance hurdle will only be satisfied where the TSR value is positive, and if the TSR value is negative the LTI will not vest. The Committee is responsible for assessing performance and the LTIs to successfully vest. To assist in this assessment, the Committee receives detailed independent reports from Orient Capital Pty Ltd calculating the TSR performance and ranking against the comparator group. 4. FY2018 SENIOR EXECUTIVE REMUNERATION OUTCOMES AND THE LINK TO COMPANY PERFORMANCE 4.1 Senior executive remuneration mix For FY2018, the remuneration for senior executives was reviewed in June 2017 in the context of the benchmarking report of May 2017. Consistent with the process for other employees, fixed remuneration was increased by CPI for most of the other senior executives; however a review of each individual’s experience, performance and alignment with comparative roles resulted in some receiving a higher increase. Table 4.1 sets out the current named senior executives’ target remuneration mix for FY2018. It reflects the STI opportunity available if the performance conditions were satisfied at target, and the value of the LTI as determined by the 10-day volume weighted average price (VWAP) of the Company’s shares as awarded at the beginning of the period. t r o p e R l a u n n A 8 1 0 2 5 4 Remuneration Report For the year ended 30 June 2018 Table 4.1 FY2018 Senior executive target remuneration mix Base pay and superannuation or retirement benefit Target short term incentive Target long term incentive Total target remuneration MD & CEO CFO Other senior executives 37% 40% 57% 36% 30% 16% 27% 30% 27% 100% 100% 100% ERM Power aims to align senior executive remuneration to strategic and business objectives and the creation of shareholder wealth. There will not always be a direct correlation between the statutory key performance measures and total variable remuneration awarded to senior executives due to the remuneration mix (see Table 4.1), which consists of a mixed focus on annual profit, operational targets, people and engagement goals set by the Board, and the ranking of TSR performance against peers. 4.2 Short term incentives ERM Power has a stated and agreed corporate strategy from which the Company’s FY2018 Balanced Scorecard was derived. The scorecard has three dimensions: • • • people – engagement and enablement; financial and operational; and strategic imperatives. The below measures are assessed based on outcomes for FY2018 and an achievement % is allocated, with the achievement % scaled from a threshold of 80% of target against each measure. A 0% outcome is assigned if the achievement is below 80% of target and a maximum outcome of 150% of the base weighting is possible for target overachievement. Table 4.2 FY2018 Corporate targets – Balanced scorecard Measure Target Weighting Achievement Outcome Commentary People — engagement and enablement Collaboration Learning & Development Financial and Operational Improve by five points1 100% completed plans 10% 10% 71 15% · Outcome reflects exceedance of targets 100% 15% Load AU & US 26.5TWh 10% 19.2TWh2 10% · Achievement reflects continuing operations only. Outcome is moderated for US performance. Underlying NPAT $13.0m 20% $30.2m2 20% · Achievement reflects continuing Cash proxy (EBITAF-capex- finance costs) Strategic Imperatives3 Group Medium-term growth drivers in key divisions $20.7m 10% $39.9m2 10% · Achievement reflects continuing operations only. Outcome is moderated for US performance. operations only. Outcome is moderated for US performance. Positioned to budget growth in key financial metrics FY20193 Positioned to deliver key commercial targets and outcomes3 15% Target met 15% · Key strategic programs underway positioning business well 25% Targets met 25% · Achieved Totals 100% 110% 1 Hay Group Employee Engagement and Enablement Survey, February 2017 and Pulse surveys FY2018 2 Assessment adjusted for discontinued businesses. Outcome reflects outperformance of the continuing business 3 Specific target commercially sensitive For senior executives, the awarding of STIs is weighted evenly based on performance against the individual’s targets and the corporate targets shown above, other than the MD & CEO whose STI is based on the corporate target alone. The table below provides details of the STI outcomes for current executive KMP in the reporting period and the comparatives for the FY2017 STI. Payment of the STI is at the Board’s discretion. R E W O P M R E 6 4 Table 4.3 STI Achievement Jon Stretch Mitch Anderson Gregg Buskey David Guiver Megan Houghton Derek McKay Steve Rogers James Spence Actual 110% 0% 36% 38% 37% 37% 34% 86% FY2018 STI1 Target 100% Maximum 150% Actual 120% FY2017 STI1 Target 100% Maximum 150% 30% 30% 30% 30% 30% 30% 75% 45% 45% 45% 45% 45% 45% 112.5% 26% 39% 40% 36% 37% 35% 90% 30% 30% 30% 30% 30% 30% 75% 45% 45% 45% 45% 45% 45% 112.5% 1 Percentage of base salary, other than for James Spence, which is a percentage of fixed annual remuneration (base salary plus superannuation) 4.3 Long term incentives The table below shows the Group’s financial performance over the last five financial years as required by the Corporations Act 2001, together with the proportion of performance-based LTI vesting metric which is designed to align the interests of senior executives to the Company’s shareholders. Table 4.4 Shareholder wealth financial data Revenue and other income EBITDAF2 Statutory NPAT3 attributable to equity holders Underlying NPAT4 Basic (loss) / earnings per share Underlying (loss) / earnings per share Dividend per share Closing share price at 30 June 3 year Total Shareholder Return5 LTI vesting Year ended 30-Jun-18 Year ended 30-Jun-17 Year ended 30-Jun-16 Year ended 30-Jun-15 Year ended 30-Jun-14 Actual 3,280.61 Actual 2,790.21 Actual 2,763.3 Actual 2,316.4 Actual 2,076.5 97.51 (80.7) 30.21 (32.9) 12.31 7.5 1.48 (29.8) 0.0 78.21 (1.1) (16.1)1 (0.4) (6.6)1 7.0 1.20 (18.4) 0.0 68.4 35.8 19.2 14.8 7.9 12.0 0.84 (51.2) 0.0 81.5 65.9 32.3 27.4 13.4 12.0 2.32 47.4 100.0 67.9 (23.9) 26.3 (10.6) 11.6 12.0 1.82 32.8 77.9 $m $m $m $m cents cents cents $ % % 1 Excludes discontinued operations. 2 Earnings before net interest costs, tax, depreciation, amortisation, impairment and net fair value gains / losses on financial instruments designated at fair value through profit and loss. EBITDAF excludes any profit or loss from associates. 3 Statutory net profit after tax attributable to equity holders of the Company. 4 Underlying NPAT excludes the after tax effect of unrealised marked to market changes in the fair value of financial instruments, impairment and gains / losses on onerous contracts and other significant items. Underlying NPAT excludes any profit or loss from associates. TSR outcomes are provided by an external supplier. The basic calculation of TSR is: TSR = (end average share price x re-investment factor) - 1 x 100 5 Average share prices are based on a 60 trading day volume weighted average price (VWAP). All share prices (and dividends) used are adjusted prices, which take into account the impact of any capital changes such as return of capital dividend, rights and bonus issues. The re-investment factor represents the cumulative number of shares held at the end of the performance period. It commences with a notional shareholding of one share and assumes dividends are reinvested during the performance period, resulting in a notional shareholding of greater than one share at the end of the performance period (assuming dividends are paid in the period). Franking credits are excluded from TSR calculations. start average share price Table 6.2 details the LTI equity performance based remuneration allocated, forfeited and vested to KMP in during the reporting period. For accounting purposes, LTIs equity are is shown at fair value as determined by the accounting standards and expensed over the performance period. • • • The LTI which was awarded in FY2015 for which the three-year performance period expired on 30 June 2017 was forfeited during the period. The three-year performance period had been significantly affected by the falls in the Company’s share price in October 2015 and June 2016. In August 2018 the Committee determined the FY2016 LTI for which the three-year performance period expired on 30 June 2018 will also be forfeited, which result will be shown in FY2019 Remuneration Report. LTI granted during the period - The FY2018 LTI target rate determined for each individual is based on a percentage of annual salary, and for the reporting period it was based on awards of 75% for the MD & CEO as approved by shareholders at the 2017 AGM, 75% for the CFO and 50% for other executive KMP. t r o p e R l a u n n A 8 1 0 2 7 4 Remuneration Report For the year ended 30 June 2018 5. NON-EXECUTIVE DIRECTORS’ FEES Fees are determined by the demands on, and responsibilities of directors and are reviewed annually by the Board. Independent advice may be sought from remuneration consultants to ensure directors’ fees are appropriate and in line with the market. The last review of fees was conducted in May 2015. Non-executive directors’ fees are determined within an aggregate fee pool limit of $1,100,000, an amount approved by shareholders at the Annual General Meeting held on 31 October 2013. Any director who devotes special attention to the business of the Company, or who otherwise performs services which in the opinion of the directors are outside the scope of the ordinary duties of a director, or who at the request of the directors engage in any journey on the business of the Company, may be paid extra remuneration as determined by the directors which will not form part of the aggregate fee pool limit above. Non-executive directors do not receive any performance-related remuneration or retirement allowances outside of statutory superannuation entitlements. Fees received by each non-executive director comprise a base fee together with additional fees dependent on the various offices they hold as set out in Table 5.1, with superannuation contributions made at the rates and limits prescribed from time to time by legislation. Table 5.1 Non-executive director fees (excluding superannuation) Fee type Chair Non-executive directors Deputy Chair (in addition to above fee) Additional fees Strategy Lead Audit & Risk Committee - chair Audit & Risk Committee - member Remuneration & Nomination Committee - chair Remuneration & Nomination Committee - member Representation on non-wholly owned subsidiary Boards FY2018 FY2017 $ 190,000 108,000 30,000 25,000 20,000 10,000 10,000 5,000 $ 190,000 108,000 30,000 25,000 20,000 10,000 10,000 5,000 25,000 each 25,000 each Although there have been no increases in base or additional fees since FY2015, the change from the prior year in individual directors’ cash salary and fees reflect the change in committee composition. On 26 October 2016 Tony Iannello assumed the chair of the Audit & Risk Committee, whilst Tony Bellas assumed the chair vacated by Tony Iannello on the Remuneration & Nomination Committee. The accounting value of fees paid to each non-executive director is shown in Table 5.2. Table 5.2 Accounting value of non-executive director fees Short-term benefits Post-employment benefits Cash salary and fees ($) Non-monetary benefits1 ($) Superannuation entitlement ($) Total remuneration per income statement ($) 210,000 208,413 123,000 123,000 128,276 87,257 133,000 131,413 108,964 - 16,083 191,413 108,000 108,000 827,323 892,246 7,939 8,795 - - 979 1,800 - 1,080 - - 933 13,243 - - 9,851 24,918 19,950 19,799 11,685 11,685 934 934 12,635 12,484 10,352 - 1,528 18,184 10,260 10,260 67,344 77,407 237,889 237,007 134,685 134,685 130,189 89,991 145,635 144,977 119,316 - 18,544 222,840 118,260 118,260 904,518 994,571 Notes: 1 Non-monetary benefits include foreign tax advice, health assessments, car parking benefits and associated FBT related items. 2 Appointed 26 October 2016. 3 Appointed 14 July 2017. 4 Resigned 14 July 2017. Tony Bellas Albert Goller Georganne Hodges2 Tony Iannello Philip St Baker3 Trevor St Baker4 Wayne St Baker Total FY 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 R E W O P M R E 8 4 8 n o i t a m r o f n I y r a t n e m e p p u S l t n e m e t a t S e m o c n I n i d e s n e p x E s t fi e n e b m r e t g n o L s t fi e n e b m r e t t r o h S . s e t o n 1 . 6 e b a t l r o f 2 5 e g a p o t r e f e R . ) 2 5 e g a p n o s e t o n e e s ( d o i r e p , s d r a d n a t s g n i t n u o c c a e h t f o s t n e m e r i u q e r e h t h t i w e c n a d r o c c a n i d e s n e p x e d o i r e p g n i t r o p e r i s u o v e r p d n a t n e r r u c t a h t n i i P M K e h t y b d e v e c e r n o i t a r e n u m e r d e t s e v f o e u a v e h t l i t c e fl e r o t d e d v o r p n o i t a m r o f n i l y r a t n e m e p p u s h t i w e h t r o f P M K e v i t u c e x e s ’ p u o r G e h t r o f d e s i n g o c e r e s n e p x e n o i t a r e n u m e r e h t f o s l i a t e d s w o h s e b a t g n w o l i l l o f e h T I I S T N A R G Y T U Q E D N A N O T A R E N U M E R E V T U C E X E R O F S E L B A T I . 6 n o i t a r e n u m e r P M K e v i t u c e x E 1 . 6 e b a T l 2 5 7 , 4 5 5 2 6 0 , 7 1 0 , 1 9 5 0 2 5 , 9 5 0 2 5 , 6 1 0 , 1 4 7 , 4 3 6 0 0 6 2 0 1 , 9 5 5 4 4 6 2 3 4 , 9 7 7 , 9 8 5 , 7 0 0 2 0 4 9 3 7 , 4 9 5 6 4 4 , 1 5 2 0 0 4 4 7 6 , 3 8 3 0 7 4 , 8 6 5 , 7 1 5 6 6 3 9 8 3 , - - - - - - c 0 8 5 , 1 4 1 ) 0 6 5 0 5 1 ( , - ) 3 9 4 4 1 3 ( , e 1 5 3 , 2 4 1 , ) 3 7 9 5 6 2 ( - ) 3 4 4 9 2 2 ( , e 1 5 0 , 1 5 1 ) 6 3 8 9 4 3 ( , - ) 8 6 1 , 9 0 3 ( 8 8 8 6 9 , e 4 0 0 4 8 , ) 4 3 3 , 6 7 2 ( - - - - - - ) 4 4 8 , 1 6 1 ( e 9 9 4 4 6 1 , , ) 1 6 0 4 4 3 ( - , ) 5 1 0 3 4 3 ( e 2 7 6 6 2 1 , , ) 5 5 5 0 6 2 ( - , ) 7 4 4 2 8 2 ( e 0 0 0 0 5 4 , , ) 0 7 9 2 3 6 ( - , ) 5 7 9 4 2 6 ( 6 6 3 , 6 1 7 , 1 - e 7 5 8 8 6 8 , ) 2 1 5 , 2 7 2 , 1 ( , 3 0 9 0 1 4 , 1 , 1 0 0 0 0 6 - ) 2 4 7 , 6 5 2 , 1 ( l a t o T d e t s e v n o i t a r e n u m e r m r e t y t i u q e g n i t s e v g n o L : d d A 9 r a e y t n e r r u c I T S : d d A n i g n i t s e v : s s e L s l a u r c c a g n i t n u o c c A l a t o T e m o c n i r e p 8 t n e m e t a t s n o i t a r e n u m e r , 1 2 0 0 2 1 , 2 4 4 6 , 7 6 0 2 , 6 9 9 9 4 7 , 7 2 1 , 5 1 9 4 2 7 , 2 8 6 7 8 0 2 6 6 , 4 6 5 8 8 7 , 5 7 1 , 1 1 7 1 8 1 , 0 9 6 0 9 2 3 1 4 , , 2 6 9 3 5 8 8 9 3 , 3 1 8 1 5 4 , 1 5 6 3 1 8 , 1 7 6 3 7 9 , 7 4 1 , 1 8 6 6 , 7 2 1 , 1 L S L l a u r c c A - - 0 8 7 , 1 2 9 5 , 1 9 9 9 3 1 , 0 0 5 , 5 1 7 6 7 4 8 4 7 5 1 , 9 1 1 7 3 , 6 1 3 5 8 4 1 , 2 5 6 , 2 5 5 3 9 6 0 1 , 9 4 0 0 2 , 4 6 2 9 5 1 , 7 0 9 6 1 , 3 7 9 9 4 , 2 9 0 6 9 , 6 1 6 9 1 , 0 5 0 , 1 5 1 5 2 9 0 0 1 , 4 7 3 8 2 , 9 4 0 0 2 , 7 0 7 , 4 4 1 6 6 6 2 7 , - 8 6 9 3 1 , 3 0 0 4 8 , - - - - 1 1 8 9 1 , ) 3 6 4 2 ( , 5 6 9 4 , 3 8 6 5 , ) 7 0 1 , 2 1 ( 4 0 8 3 4 , 5 1 1 , 2 0 1 9 4 0 0 2 , , 9 1 9 3 2 1 8 5 5 3 1 , 3 7 9 9 4 , 4 9 8 4 9 , 6 1 6 9 1 , 2 7 6 6 2 1 , 3 5 9 0 9 9 2 1 1 , 1 1 9 8 5 , 6 7 1 9 4 0 0 2 , 4 7 1 , 1 4 4 4 5 3 , 3 6 , 1 1 4 2 1 1 6 1 6 9 1 , 0 0 0 0 5 4 , 3 7 9 9 4 , 1 5 1 , 7 3 1 6 1 6 9 1 , 8 9 4 4 6 1 , - - - - - 7 0 5 , 6 ) 4 6 ( 4 2 6 , 7 3 1 9 ) 5 2 8 , 1 2 ( 4 0 8 3 4 , 2 7 1 , 5 2 1 9 4 0 0 2 , 3 7 6 , 7 6 1 2 8 6 , 7 2 ) 9 8 5 , 6 ( 0 6 3 0 1 1 , 6 1 6 9 1 , 0 5 3 , 2 4 1 7 2 3 , 6 4 ) 6 6 0 , 7 3 ( - - - - 8 7 8 4 , , 7 5 2 0 0 3 6 1 6 9 1 , , 1 6 4 6 3 9 3 1 7 , 7 - , 3 6 9 8 3 3 9 4 0 0 2 , , 8 1 8 5 4 8 7 4 3 9 5 , 0 8 6 3 2 , r e h t O y t i u q e d e s a b 7 s t fi e n e b m r e t - g n o L n a P l e v i t n e c n I - t s o P l - y o p m e t n e m 6 s t fi e n e b 5 e v i t n e c n i m r e t - t r o h S r e h t O 4 s t fi e n e B 3 l a u r c c a d n a s t i f e n e b e v a e l l a u n n a y r a t e n o m n o N 1 5 3 , 5 8 1 1 4 1 , 4 1 3 8 4 5 4 1 , 1 8 2 , 3 0 1 9 4 0 0 2 , 7 8 8 3 4 1 , - - 6 9 6 , 2 3 1 0 0 2 4 1 , - 6 5 3 , 7 1 3 4 7 , 6 1 8 0 9 2 3 , 8 2 9 5 1 , 8 0 5 , 6 e s a B 2 h s a c - y r a a s l 4 8 3 0 3 8 , 4 8 3 0 8 7 , 6 3 8 2 5 5 , 4 2 2 4 5 5 , 0 0 0 5 9 3 , 0 0 0 5 6 3 , 0 0 0 5 1 4 , 0 0 0 0 8 3 , , 4 9 3 0 9 3 6 8 4 6 3 2 , 4 1 0 , 7 5 4 4 1 6 , 7 4 4 4 6 1 , 7 6 3 4 6 1 , 7 6 3 , 2 7 4 0 9 4 , 4 8 3 0 8 4 $ A $ A $ A $ A $ A $ A $ A $ A $ A $ A $ A $ A $ A $ A $ A $ A 8 1 0 2 7 1 0 2 8 1 0 2 7 1 0 2 8 1 0 2 7 1 0 2 8 1 0 2 7 1 0 2 8 1 0 2 7 1 0 2 8 1 0 2 7 1 0 2 8 1 0 2 7 1 0 2 8 1 0 2 7 1 0 2 ) 6 1 0 2 v o N 1 2 n o t n e m t n o p p a i n o t g u o H n a g e M P M K r o f r a e y - t r a p 7 1 0 2 ( y a K c M k e r e D s r e g o R e v e t S e c n e p S s e m a J t r o p e R l a u n n A 8 1 0 2 9 4 y e k s u B g g e r G i r e v u G d v a D i 1 n o s r e d n A h c t i M h c t e r t S n o J ) O E C & D M ( Remuneration Report For the year ended 30 June 2018 Table 6.2 Terms and conditions of equity grants and long term benefits The terms and conditions of each grant of a cash bonus, performance-related bonus or share-based compensation benefit affecting compensation of disclosed executives in the current or a future reporting period, and the maximum value of the grant that may vest in future financial years is shown below: Refer to page 52 for table 6.2 notes Award1 Service and performance criteria Grant date Nature of compensation2 Jon Stretch FY2017 STI Note 4 27/10/2017 FY2015 LTI FY2016 LTI FY2017 LTI Note 5 30/10/2015 Note 6 30/10/2015 Note 7 26/10/2016 FY2018 LTI Note 8 23/10/2017 Mitch Anderson FY2017 STI Note 4 15/09/2017 Units in EST Units in EST Units in EST Units in EST Units in EST Cash FY2015 LTI FY2016 LTI FY2017 LTI FY2018 LTI Note 5 13/11/2014 Units in EST Note 6 14/03/2016 Phantom Shares Note 7 Note 8 7/07/2016 Phantom Shares 1/07/2017 Phantom Shares Gregg Buskey FY2017 STI Note 4 15/09/2017 FY2015 LTI FY2016 LTI FY2017 LTI FY2018 LTI Note 5 13/11/2014 Note 6 Note 7 Note 8 8/07/2015 1/07/2016 1/07/2017 David Guiver FY2017 STI Note 4 15/09/2017 Units in EST Units in EST Units in EST Units in EST Units in EST Units in EST Retention Note 9 19/08/2013 Performance Rights FY2015 LTI FY2016 LTI FY2017 LTI FY2018 LTI Note 5 13/11/2014 Note 6 Note 7 Note 8 8/07/2015 1/07/2016 1/07/2017 Megan Houghton FY2017 STI Note 4 15/09/2017 Note 10 24/11/2016 Units in EST Units in EST Units in EST Units in EST Units in EST Units in EST Commencement Award (1) Commencement Award (2) Note 10 24/11/2016 Units in EST A $96,888 $1.11 87,681 87,681 2019 A $20,185 FY2018 LTI Note 8 1/07/2017 Derek McKay FY2017 STI Note 4 15/09/2017 FY2015 LTI FY2016 LTI FY2017 LTI Note 5 13/11/2014 Note 6 Note 7 8/07/2015 1/07/2016 Units in EST Units in EST Units in EST Units in EST Units in EST Retention Note 9 24/09/2014 Performance Rights FY2018 LTI Note 8 1/07/2017 Steve Rogers FY2017 STI Note 4 15/09/2017 FY2015 LTI FY2016 LTI FY2017 LTI Note 5 13/11/2014 Note 6 Note 7 8/07/2015 1/07/2016 Units in EST Units in EST Units in EST Units in EST Units in EST Retention Note 9 24/09/2014 Performance Rights FY2018 LTI Note 8 1/07/2017 James Spence FY2017 STI Note 4 15/09/2017 Commencement Award (2) Note 11 13/08/2015 FY2016 LTI FY2017 LTI FY2018 LTI Note 6 13/08/2015 Note 7 Note 8 1/07/2016 1/07/2017 Units in EST Units in EST Units in EST Units in EST Units in EST Units in EST R E W O P M R E 0 5 Fair Value at Grant Date Equity balance at the start of % Granted as compensation the year Vested Forfeit Equity balance Financial Maximum at the end of the year Year award remaining value of award that may vest may vest3 Unvested Number % Number % Number % Unvested Total per unit A $868,857 $1.29 - 676,048 100% 676,048 100% 517,309 100% 100% 100% 253,980 633,361 2020 A $194,902 517,309 A $263,181 140,057 100% 126,683 100% 91,334 100% 54,059 100% US $256,174 $1.09 - 234,083 100% A $142,351 $1.39 - 102,766 100% 102,766 100% A $103,352 $0.63 - 164,051 100% A $151,051 $1.39 - 109,046 100% 109,046 100% A $108,585 $0.63 A $84,004 $1.39 172,357 100% 60,644 100% 60,644 100% A $96,888 $1.11 87,681 87,681 100% A $159,665 $1.14 140,057 A $320,015 $1.26 253,980 A $430,685 $0.68 633,361 A $331,078 $0.64 US $109,767 N/A A $145,685 $1.15 US $60,598 $0.59 US $349,163 $1.77 - - 126,683 101,949 197,490 A $105,034 $1.15 A $108,376 $1.44 91,334 75,261 A $112,569 $0.57 197,490 A $250,000 $2.71 A $62,168 $1.15 A $110,254 $1.44 92,285 54,059 76,565 A $117,195 $0.57 205,606 - - - - - - 114,997 93,342 242,190 140,057 54,059 76,565 198,661 140,057 A $102,147 $0.63 A $164,499 $1.39 A $132,247 $1.15 A $134,412 $1.44 A $138,048 $0.57 A $250,002 $1.79 A $119,578 $0.63 A $126,672 $1.39 A $62,168 $1.15 A $110,254 $1.44 A $113,237 $0.57 A $250,002 $1.79 A $96,069 $0.63 - 152,490 100% A $450,000 $1.39 - 324,863 100% 324,863 100% A $52,059 $2.22 23,450 23,450 100% A $122,234 $1.39 87,938 A $231,307 $0.57 405,801 A $200,366 $0.63 - 318,042 100% - - - - - - - - - - - - - - - - 101,949 197,490 234,083 75,261 197,490 164,051 92,285 76,565 205,606 172,357 93,342 242,190 140,057 189,806 76,565 198,661 140,057 152,490 87,938 405,801 318,042 2020 US $203,495 US $200,745 2020 A $40,288 2018 2018 2019 2021 2018 2018 2019 2021 2018 2018 2019 2021 2018 2019 2018 2019 2020 2021 2018 2018 2021 2018 2018 2019 2020 2020 2021 2018 2018 2019 2020 2020 2021 2018 2018 2019 2020 2021 A $- A $- A $- US $- A $- US $- A $- A $- A $- A $74,643 A $- A $4,167 A $41,943 A $78,423 A $- A $- A $- A $- A $49,407 A $67,917 A $86,362 A $40,527 A $67,917 A $69,383 A $- A $- A $- A $- A $- A $- A $- A $- A $- A $82,784 A $144,709 162,138 100% 118,755 100% 118,755 100% 114,997 100% 162,138 A $73,773 189,806 100% 91,447 100% 91,447 100% 54,059 100% FY2015 LTI FY2016 LTI FY2017 LTI Note 5 30/10/2015 Note 6 30/10/2015 Note 7 26/10/2016 FY2018 LTI Note 8 23/10/2017 Mitch Anderson FY2017 STI Note 4 15/09/2017 Note 5 13/11/2014 Units in EST Note 6 14/03/2016 Phantom Shares Note 7 Note 8 7/07/2016 Phantom Shares 1/07/2017 Phantom Shares Note 5 13/11/2014 Note 6 Note 7 Note 8 8/07/2015 1/07/2016 1/07/2017 Note 5 13/11/2014 Note 6 Note 7 Note 8 8/07/2015 1/07/2016 1/07/2017 Retention Note 9 19/08/2013 Performance Rights FY2015 LTI FY2016 LTI FY2017 LTI FY2018 LTI FY2015 LTI FY2016 LTI FY2017 LTI FY2018 LTI FY2015 LTI FY2016 LTI FY2017 LTI FY2018 LTI Award (1) Award (2) Megan Houghton FY2017 STI Note 4 15/09/2017 Award1 Service and performance criteria Grant date Nature of compensation2 Fair Value at Grant Date Equity balance at the start of the year % Granted as compensation Vested Forfeit Equity balance at the end of the year Total per unit Unvested Number % Number % Number % Unvested Financial Year award may vest Maximum remaining value of award that may vest3 Jon Stretch FY2017 STI Note 4 27/10/2017 A $868,857 $1.29 - 676,048 100% 676,048 100% A $159,665 $1.14 140,057 A $320,015 $1.26 253,980 A $430,685 $0.68 633,361 A $331,078 $0.64 US $109,767 N/A A $145,685 $1.15 US $60,598 $0.59 US $349,163 $1.77 - - 126,683 101,949 197,490 517,309 100% 100% 100% Gregg Buskey FY2017 STI Note 4 15/09/2017 A $142,351 $1.39 - 102,766 100% 102,766 100% US $256,174 $1.09 - 234,083 100% David Guiver FY2017 STI Note 4 15/09/2017 A $151,051 $1.39 - 109,046 100% 109,046 100% A $105,034 $1.15 A $108,376 $1.44 91,334 75,261 A $112,569 $0.57 197,490 A $103,352 $0.63 - 164,051 100% Commencement Note 10 24/11/2016 A $96,888 $1.11 87,681 87,681 100% A $250,000 $2.71 A $62,168 $1.15 A $110,254 $1.44 92,285 54,059 76,565 A $117,195 $0.57 205,606 A $108,585 $0.63 A $84,004 $1.39 - - 172,357 100% 60,644 100% 60,644 100% 140,057 100% 126,683 100% 91,334 100% 54,059 100% - - 253,980 2018 2018 2019 A $- A $- A $- 633,361 2020 A $194,902 517,309 - - 101,949 197,490 234,083 - - 75,261 197,490 164,051 - 92,285 - 76,565 205,606 172,357 - - 2021 2018 2018 2019 A $263,181 US $- A $- US $- 2020 US $203,495 2021 2018 2018 2019 US $200,745 A $- A $- A $- 2020 A $40,288 2021 2018 2019 2018 2019 2020 2021 2018 2018 A $74,643 A $- A $4,167 A $- A $- A $41,943 A $78,423 A $- A $- Commencement Note 10 24/11/2016 Units in EST A $96,888 $1.11 87,681 87,681 2019 A $20,185 FY2018 LTI Note 8 1/07/2017 Derek McKay FY2017 STI Note 4 15/09/2017 FY2015 LTI FY2016 LTI FY2017 LTI Note 5 13/11/2014 Note 6 Note 7 8/07/2015 1/07/2016 FY2018 LTI Note 8 1/07/2017 Steve Rogers FY2017 STI Note 4 15/09/2017 FY2015 LTI FY2016 LTI FY2017 LTI Note 5 13/11/2014 Note 6 Note 7 8/07/2015 1/07/2016 Retention Note 9 24/09/2014 Performance Rights Retention Note 9 24/09/2014 Performance Rights A $102,147 $0.63 A $164,499 $1.39 A $132,247 $1.15 A $134,412 $1.44 A $138,048 $0.57 A $250,002 $1.79 A $119,578 $0.63 A $126,672 $1.39 A $62,168 $1.15 A $110,254 $1.44 A $113,237 $0.57 A $250,002 $1.79 - - 114,997 93,342 242,190 140,057 - - 54,059 76,565 198,661 140,057 162,138 100% 118,755 100% 118,755 100% 114,997 100% 189,806 100% 91,447 100% 91,447 100% 54,059 100% FY2018 LTI Note 8 1/07/2017 A $96,069 $0.63 - 152,490 100% James Spence FY2017 STI Note 4 15/09/2017 A $450,000 $1.39 - 324,863 100% 324,863 100% Commencement Note 11 13/08/2015 A $52,059 $2.22 23,450 23,450 100% Award (2) FY2016 LTI FY2017 LTI FY2018 LTI Note 6 13/08/2015 Note 7 Note 8 1/07/2016 1/07/2017 A $122,234 $1.39 87,938 A $231,307 $0.57 405,801 A $200,366 $0.63 - 318,042 100% 162,138 - - 93,342 242,190 140,057 189,806 - - 76,565 198,661 140,057 152,490 - - 87,938 405,801 318,042 2021 2018 2018 2019 2020 2020 2021 2018 2018 2019 2020 2020 2021 2018 2018 2019 2020 2021 A $73,773 A $- A $- A $- A $49,407 A $67,917 A $86,362 A $- A $- A $- A $40,527 A $67,917 A $69,383 A $- A $- A $- A $82,784 A $144,709 t r o p e R l a u n n A 8 1 0 2 1 5 Units in EST Units in EST Units in EST Units in EST Units in EST Cash Units in EST Units in EST Units in EST Units in EST Units in EST Units in EST Units in EST Units in EST Units in EST Units in EST Units in EST Units in EST Units in EST Units in EST Units in EST Units in EST Units in EST Units in EST Units in EST Units in EST Units in EST Units in EST Units in EST Units in EST Units in EST Units in EST Units in EST Units in EST Remuneration Report For the year ended 30 June 2018 Notes for Table 6.1: Notes for Table 6.2: 1. 2. 3. 4. 5. 6. 7. 8. Transferred to US on 1 February 2015 with relocation expenses met by the Group. Existing LTI awards will continue to be expensed in Australia, whilst new LTI awards under the Phantom Equity Plan and other remuneration is expensed and paid in US$. Executive remuneration is reported in A$ using the average exchange rates of A$1=US$0.7753 for FY2018, and A$1=US$0.7545 for FY2017. Each senior executive is employed under an on-going employment contract, for which the termination benefits are payable at the option of the Company in lieu of notice. The notice periods (by the employee or the Company) in respect of each of the executives listed is 6 months, however for Jon Stretch the Company has an additional right of termination in certain circumstances by providing 3 months’ written notice. Non-monetary benefits includes annual benefits of salary continuance insurance premiums paid for Australian employees, health insurance coverage for US residents and executive health assessments. Other benefits include non-recurring items, such as a retention accrual for Mitch Anderson given the potential sale of the US business, relocation allowance in regards to professional tax services, cashing out of annual leave, and subsidisation of a family visit during an extended US secondment for Derek McKay. Short term incentives in respect of FY2018 have not been paid by the date of this report, with accounting accruals shown for the expected payments based on the STI achievements reported in Table 4.3. Australian superannuation entitlements and US 401K retirement plan contributions. Other equity benefits refer to the accounting expense of retention and commencement awards which will vest subject to service conditions. The amounts shown are as expensed in the income statement but which may not reflect the benefit actually received by the executive in that year. In accordance with AASB2, equity benefits include a portion of the value of equity that has not vested during the financial year as well as the present value of expected dividends over the vesting period. The amount included as remuneration does not necessarily reflect the benefit (if any) that may ultimately be realised by the executive if vesting occurs. Supplementary Information is provided to reflect the value of vested remuneration actually received by the executive in that year, with equity values based on the fair value as at the date of grant. 9. The STI vesting in the current year relates to performance in FY2017. Awards were made in cash (“c”) or equity (“e”). 1. 2. 3. 4. 5. 6. 7. 8. 9. 10. 11. There have been no alterations in terms or conditions since grant date. The nature of compensation may be by way of cash or equity (units in the Employee Share Trust (EST), Performance Rights or Phantom Shares for US employees. The maximum value yet to vest for Australian awards has been determined as the amount of fair value as at grant date that is yet to be expensed in a future accounting period. The maximum value yet to vest for the US award has been determined as the amount that may be expensed in a future accounting period based on the closing share price and exchange rate as at 30 June 2018. The minimum value yet to vest will always be zero, as equity will be forfeited if the vesting conditions are not met. The FY2017 STI achievements were disclosed in Table 4.3 of the FY2017 Remuneration Report. The award by way of equity was included for shareholder approval at the 2017 Annual General Meeting for Jon Stretch. FY2015 LTI TSR was determined to be -18.4%, which in accordance with the vesting conditions resulted in 100% of the FY2015 LTI being forfeited. FY2016 LTI vesting was subject to continuation of employment through to 30 June 2018 and TSR performance measured against the TSR performance of a comparator group being those companies in the Standard & Poor’s (S&P) ASX 300 index at the beginning of the performance period. On 16 August 2018 the Committee determined that the TSR vesting conditions required at the date of grant had not been met, and the FY2016 LTI awards were forfeited by all participants. FY2017 LTI vesting is subject to continuation of employment through to 30 June 2019 and TSR performance measured against the TSR performance of a comparator group being those companies in the Standard & Poor’s (S&P) ASX 300 index at the beginning of the performance period. FY2018 LTI vesting is subject to continuation of employment through to 30 June 2020 and TSR performance measured against the TSR performance of a comparator group being those companies in the Standard & Poor’s (S&P) ASX 300 index at the beginning of the performance period. Performance Rights granted under an employee retention strategy, subject to a 5 year vesting period and satisfied, at the Board’s discretion, in cash or equity, subject to continuous full-time employment with the Company. The vesting value will be the number of Performance Rights held, multiplied by the higher of either the notional issue price, or the 10 day VWAP prior to the date of vesting. Commencement award of $200,000 of units in the Employee Share Trust. Vesting subject to continued employment to each vesting date. 50% to vest in November 2017 with the balance to vest in November 2018. Fair value as determined by AASB2 and expensed over the vesting period. Commencement award of $100,000 of units in the Employee Share Trust. Vesting subject to continued employment to each vesting date. 50% vested on the first anniversary of the commencement date, and the remaining 50% are to vest on the second anniversary of the commencement date. Fair value as determined by AASB2 and expensed over the vesting period. R E W O P M R E 2 5 7. OTHER REMUNERATION DISCLOSURES 7.1 Details of shares, options and rights Unissued shares No options were granted to directors or any of the five highest remunerated officers of the Group during the reporting period or since the end of FY2018. As at the date of this report, there were no options exercisable into fully paid ordinary shares on issue, and no shares were issued during the year on the exercise of any options. Performance rights and option holdings The numbers of options or rights over ordinary shares in the Company granted under executive incentive schemes that were held during the financial year by each disclosed executive of the Group, including their related parties, are set out below: Table 7.1 Performance rights and option holdings Philip St Baker Jon Stretch Mitch Anderson1 Gregg Buskey David Guiver Megan Houghton Derek McKay Steve Rogers James Spence Balance at the start of the year Vested and exercisable Unvested Appointment or cessation as KMP Expired Balance at the end of the year Vested and exercisable Unvested - - 106,364 61,634 55,228 - 106,364 45,410 - - - - - 92,285 - 140,057 140,057 - 242,706 (242,706) - - - - - - - - - (106,364) (61,634) (55,228) - (106,364) (45,410) - - - - - - - - - - - - - - 92,285 - 140,057 140,057 - 1 Excludes Phantom Shares as not a right over issued securities. Share holdings The numbers of shares in the Company held during the financial year by each director and other disclosed executives of the Group, including their related parties, are set out in the tables below: Table 7.2 Non-executive director’s share holdings Non-executive directors1 Tony Bellas Albert Goller Georganne Hodges Tony Iannello Philip St Baker Trevor St Baker Wayne St Baker Balance at the start of the year 106,250 270,000 - 202,839 Appointment or cessation as KMP2 Other Changes3 Balance at the end of the year - - - - - 106,250 20,000 290,000 - - - 202,839 - 6,252,564 (1,489,869) 4,762,695 63,496,907 (63,496,907) 1,625,290 - - - - 1,625,290 1 No shares were held nominally other than by Trevor St Baker for which the opening balances above included 3,075,242. 2 Philip was appointed and Trevor resigned on 14 July 2017. 3 On and off market movements, dividend reinvestment plan, etc. t r o p e R l a u n n A 8 1 0 2 3 5 Remuneration Report For the year ended 30 June 2018 Table 7.3 Executive’s share holdings Executives Balance at the start of the year Vested Unvested Received on vesting of performance rights Granted as compensation Forfeit Other Changes1 Balance at the end of the year Vested Unvested Balance at the end of the year held nominally Jon Stretch 1,052,179 1,027,398 Mitch Anderson2 1,339,820 126,683 Gregg Buskey David Guiver 142,416 364,085 180,227 336,230 Megan Houghton - 175,362 Derek McKay Steve Rogers James Spence 456,589 450,529 152,364 329,285 218,992 517,189 1 On and off market movements, dividend reinvestment plan etc. 2 Excludes phantom shares. - - - - - - - - 1,193,357 (140,057) - 1,728,227 1,404,650 732,179 - (126,683) (43,800) 1,296,020 - 266,817 (91,334) 1 245,183 436,802 281,403 (54,059) (55,350) 233,923 454,528 222,782 - - 148,325 249,819 - 9 - - 308,561 (114,997) (56,702) 518,642 525,338 45,000 243,937 (54,059) 642,905 - - - 243,811 427,716 - 567,305 811,781 195,542 7.2 Loans to key management personnel Details of loans made to KMP or close members of the family of a member of the KMP, or an entity over which the KMP has control or significant influence, are set out below: Aggregate amounts Balance at the start of the year Interest paid and payable for the year Interest not charged Balance at the end of the year Number in Group at the end of the year FY2018 $40,679 $ 1,034 $- $- - The above loan represents an employee shareholder loan that was offered to certain senior executives in 2007 and 2008 to participate in a share loan incentive plan which enabled them to subscribe for shares. The loan was subject to a loan deed and was interest bearing at the FBT benchmark rates with recourse limited to the value of the shares. The amount shown for interest not charged in the table above represent the difference between the amount paid and payable for the year and the amount of interest that would have been charged on an arm’s-length basis. The loan was repaid in full during the period. No loans were made, guaranteed or secured, nor remain outstanding in the reporting period to any KMP or close member of the family of any KMP for an amount greater than $100,000. No write-downs or allowances for doubtful receivables have been recognised in relation to any loans made to KMP. 7.3 Other transactions with KMP During the period the Company entered into certain transactions with KMP or their related entities as outlined in note 32 of the Financial Statements. The Board is satisfied that those transactions: • • • were on terms and conditions no more favourable than those that would have been adopted if dealing at arm’s length with an unrelated person; did not have the potential to affect adversely decisions about the allocation of scarce resources made by users of the financial statements, or the discharge of accountability by the KMP; or were trivial or domestic in nature. 7.4 Voting and comments received at the 2017 Annual General Meeting The Company received more than 97% of votes cast at the 2017 AGM on the Remuneration Report when put to a poll. Although the company did not receive any specific feedback at the AGM on its remuneration practices, the Committee resolved to change the format of future long term incentives to be more aligned with common practice in the market. From FY2019 it was resolved that long term incentive awards will be via the issue of Performance Rights, which do not carry voting entitlements nor rights to dividends during the vesting period whilst performance hurdles are yet to be satisfied. R E W O P M R E 4 5 Annual Financial Statements For the year ended 30 June 2018 Contents Auditor’s Independence Declaration Financial Statements Consolidated Income Statement Consolidated Statement of Comprehensive Income Consolidated Statement of Financial Position Consolidated Statement of Changes in Equity Consolidated Statement of Cash Flows Notes to the Consolidated Financial Statements Directors’ Declaration Independent Auditor’s Report 56 57 57 58 59 60 61 62 117 118 The financial statements were authorised for issue by the directors on 23 August 2018. The directors have the power to amend and reissue the financial statements. These financial statements cover ERM Power Limited as a consolidated entity comprising ERM Power Limited and its controlled entities. The Group’s presentation currency is Australian dollars (AUD). All subsidiaries operating in Australia have a functional currency of AUD and all subsidiaries operating in the United States have a functional currency of US Dollars (USD). ERM Power Limited is a company limited by shares, incorporated and domiciled in Australia. Its registered office and principal place of business is set out on page 127. A description of the Group’s operations and of its principal activities is included in the review of operations and activities in the Directors’ Report on pages 40 to 42. The Directors’ Report does not form part of the annual financial statements. t r o p e R l a u n n A 8 1 0 2 5 5 R E W O P M R E 6 5 PricewaterhouseCoopers, ABN 52 780 433 757480 Queen Street, BRISBANE QLD 4000, GPO Box 150, BRISBANE QLD 4001T: +61 7 3257 5000, F: +61 7 3257 5999, www.pwc.com.auLiability limited by a scheme approved under Professional Standards Legislation.Auditor’s Independence DeclarationAs lead auditor for the audit of ERM Power Limited for the year ended 30 June 2018, I declare that to the best of my knowledge and belief, there have been: (a)no contraventions of the auditor independence requirements of the Corporations Act 2001in relation to the audit; and(b)no contraventions of any applicable code of professional conduct in relation to the audit.This declaration is in respect of ERM Power Limited and the entities it controlled during the period.Michael ShewanBrisbanePartnerPricewaterhouseCoopers23 August 2018 Consolidated Income Statement For the year ended 30 June 2018 CONSOLIDATED INCOME STATEMENT Continuing Operations Revenue Other income Total revenue Expenses EBITDAF Depreciation and amortisation Impairment expense Net fair value (loss) / gain on financial instruments designated at fair value through profit or loss Results from operating activities Share of net profit / (loss) of associates and joint ventures accounted for using the equity method Finance income Finance expense (Loss) / profit before income tax Income tax benefit / (expense) (Loss) / profit from continuing operations Loss from discontinued operations (attributable to equity holders of the Company) Statutory loss for the year attributable to equity holders of the Company Statutory (loss) / earnings per share based on continuing operations attributable to the ordinary equity holders of the Company Basic (loss) / earnings per share Diluted (loss) / earnings per share Statutory (loss) / earnings per share based on earnings attributable to the ordinary equity holders of the Company Basic (loss) / earnings per share Diluted (loss) / earnings per share Note 2018 $’000 2017 $’000 4 5 16 6 7 7 8 31 1 1 1 1 3,279,476 2,789,413 1,107 819 3,280,583 2,790,232 (3,183,085) (2,712,047) 97,498 (30,224) (1,034) (109,153) (42,913) 195 3,100 (27,311) (66,929) 20,195 (46,734) (33,968) (80,702) 78,185 (27,189) - 50,929 101,925 (298) 3,611 (24,487) 80,751 (61,494) 19,257 (20,330) (1,073) Cents Cents (19.03) (18.52) 7.89 7.66 Cents Cents (32.86) (31.99) (0.44) (0.43) The above Consolidated Income Statement should be read in conjunction with the accompanying notes. Operational business segment performance and underlying profit of the consolidated entity is presented in note 3, together with a reconciliation between statutory profit attributable to members of the parent entity and underlying profit. t r o p e R l a u n n A 8 1 0 2 7 5 Consolidated Statement of Comprehensive Income For the year ended 30 June 2018 CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME Statutory loss for the year Other comprehensive (loss) / income Items that may be reclassified subsequently to profit and loss Changes in the fair value of cash flow hedges (net of tax) Other comprehensive income arising from discontinued operations Items that will not be reclassified subsequently to profit and loss Changes in the fair value of financial assets at fair value through other comprehensive income (net of tax) Other comprehensive (loss) / income for the year attributable to equity holders of the Company (net of tax) Note 2018 $’000 (80,702) 2017 $’000 (1,073) 27 31 27 (223,772) 1,310 116,574 (1,342) (6) (142) (222,468) 115,090 Total comprehensive (loss) / income for the year attributable to equity holders of the Company (303,170) 114,017 Total comprehensive (loss) / income for the year attributable to equity holders of the Company arises from: Continuing operations Discontinued operations (270,512) 31 (32,658) (303,170) 135,689 (21,672) 114,017 The Consolidated Statement of Comprehensive Income should be read in conjunction with the accompanying notes. R E W O P M R E 8 5 Consolidated Statement of Financial Position As at 30 June 2018 CONSOLIDATED STATEMENT OF FINANCIAL POSITION Assets Current Assets Cash and cash equivalents Trade and other receivables at amortised cost Inventories Current tax assets Other assets Derivative financial instruments Assets classified as held for sale Total current assets Non-current assets Financial assets at fair value through other comprehensive income Investments accounted for using the equity method Derivative financial instruments Property, plant and equipment Deferred tax assets Intangible assets Leased assets Total non-current assets Total assets Liabilities Current liabilities Trade and other payables Current tax liabilities Borrowings Borrowings – limited recourse Lease liabilities Derivative financial instruments Provisions Liabilities directly associated with assets classified as held for sale Total current liabilities Non-current liabilities Borrowings – limited recourse Lease liabilities Derivative financial instruments Deferred tax liabilities Provisions Total non-current liabilities Total liabilities Net assets Equity Contributed equity Reserves (Accumulated losses) / retained earnings Total equity Note 2018 $’000 2017 $’000 24 10 11 12 13 31 29(c)/(d) 13 15 21 16 18 19 25 25 18 13 20 25 18 13 21 20 26 27 227,636 320,251 81,762 2,974 14,601 73,127 720,351 167,235 887,586 9 6,898 25,968 390,682 - 38,466 10,524 472,547 1,360,133 423,639 - 150,831 8,904 3,681 28,239 6,596 621,890 152,088 773,978 176,567 13,588 85,183 57,095 4,222 336,655 1,110,633 249,500 340,431 (2,277) (88,654) 249,500 244,616 360,947 42,257 - 6,180 325,161 979,161 - 979,161 15 6,702 81,445 391,386 13,850 89,378 14,381 597,157 1,576,318 464,314 18,088 - 8,264 3,605 33,889 14,811 542,971 - 542,971 180,653 18,375 67,453 178,380 22,606 467,467 1,010,438 565,880 335,012 220,877 9,991 565,880 The above Consolidated Statement of Financial Position should be read in conjunction with the accompanying notes. t r o p e R l a u n n A 8 1 0 2 9 5 Consolidated Statement of Changes in Equity As at 30 June 2018 CONSOLIDATED STATEMENT OF CHANGES IN EQUITY Balance at 1 July 2016 Impact of change in accounting policy Loss for the period Other comprehensive income Total comprehensive income for the year Transactions with owners in their capacity as owners: Dividends paid Issue of shares pursuant to employee incentive scheme Purchase of treasury shares Share based payment expense Balance at 30 June 2017 Loss for the period Other comprehensive loss Total comprehensive loss for the year Transactions with owners in their capacity as owners: Dividends paid Issue of shares pursuant to employee incentive scheme Purchase of treasury shares Buy-back of shares (net of transaction costs and tax) Share based payment expense Balance at 30 June 2018 Note Contributed equity $’000 Reserves $’000 332,355 103,413 - - - - - - 115,090 115,090 Total equity $’000 (Accumulated losses) / retained earnings $’000 35,635 (732) (1,073) - (1,805) 471,403 (732) (1,073) 115,090 113,285 2 26/27 26 33 1,301 5,909 (4,553) - - (23,839) (22,538) (1,153) - 3,527 - - - 4,756 (4,553) 3,527 335,012 220,877 9,991 565,880 - - - - (80,702) (80,702) (222,468) (222,468) - (222,468) (80,702) (303,170) 2 26/27 26 26 33 673 9,893 (2,675) (2,472) - - (17,943) (3,052) - (408) 2,774 - - - - (17,270) 6,841 (2,675) (2,880) 2,774 340,431 (2,277) (88,654) 249,500 The above Consolidated Statement of Changes in Equity should be read in conjunction with the accompanying notes. R E W O P M R E 0 6 Consolidated Statement of Cash Flows For the year ended 30 June 2018 CONSOLIDATED STATEMENT OF CASH FLOWS Cash flows from operating activities Receipts from customers Payments to suppliers and employees Transfer (to) / from variation margin account Interest received Income tax paid Net cash (outflow) / inflow from operating activities Cash flows from investing activities Payments for plant and equipment Proceeds on disposal of plant and equipment Payments for intangible assets Proceeds on disposal of gas assets Purchase of shares and options in non-listed companies Proceeds on sale of discontinued operations Deposit on sale of SME customer contracts Net cash outflow from investing activities Cash flows from financing activities Proceeds from borrowings including receivables financing facility Repayments of borrowings including receivables financing facility Repayments of borrowings – limited recourse Lease repayments - principle Lease repayments - interest Finance costs - other Dividends paid Payments for shares bought back Termination of US Sleever agreement Net cash inflow / (outflow) from financing activities Net (decrease) / increase in cash and cash equivalents Cash and cash equivalents at the beginning of the year Effect of exchange rate changes on cash and cash equivalents Cash and cash equivalents at the end of the year Cash and cash equivalents – continuing operations Cash and cash equivalents – discontinued operations (i) Refer to note 31 for cash flows of discontinued operations. The above Consolidated Statement of Cash Flows should be read in conjunction with the accompanying notes. Note 2018 $’000 2017 $’000 4,117,624 3,488,152 (4,017,873) (3,394,711) (118,723) 3,069 (26,876) (42,779) 69,181 3,475 (14,405) 151,692 (16,036) (16,084) 177 - (33,273) (24,302) - (100) 4,253 1,450 14,921 (5,500) 11,183 - (43,529) (19,782) 1,931,000 478,665 (1,780,293) (496,026) 9 31 2 (5,264) (3,599) (779) (34,015) (17,270) (2,916) (5,121) 81,743 (4,565) 244,616 407 24 240,458 227,636 12,822 (i) (6,332) (3,201) (879) (28,720) (22,538) - - (79,031) 52,879 192,467 (730) 244,616 t r o p e R l a u n n A 8 1 0 2 1 6 Notes to the Consolidated Financial Statements Notes to the Consolidated Financial Statements SECTION 1: Financial performance 1. Earnings Per Share 2. Dividends Paid and Proposed 3. Segment Report 4. Revenue 5. Expenses 6. Net Fair Value (Loss) / Gain on Financial Instruments Designated at Fair Value through Profit and Loss 7. Net Finance Expense 8. Income Tax 9. Cash Flow Information SECTION 2: Operating assets and liabilities 10. Trade and Other Receivables at Amortised Cost 11. Inventories 12. Other Assets 13. Derivative Financial Instruments 14. Hedge Accounting 15. Property, Plant and Equipment 16. Intangible Assets 17. Impairment of Non-Financial Assets 18. Leased Assets and Liabilities 19. Trade and Other Payables 20. Provisions 21. Deferred Tax Assets and Liabilities SECTION 3: Capital and financial risk management 22. Financial Risk Management 23. Fair Value Measurement 24. Cash and Cash Equivalents 25. Borrowings 26. Contributed Equity 27. Reserves SECTION 4: Group structure 28. Parent Entity Financial Information 29. Interests in Other Entities 30. Business Combinations 31. Discontinued Operations SECTION 5: Employee remuneration 32. Key Management Personnel 33. Share Based Payments SECTION 6: Other disclosure items 34. Commitments and Contingencies 35. Related Party Disclosures 36. Auditors’ Remuneration 37. Events After the Reporting Period 38. Basis of Preparation Definitions The directors believe that EBITDAF, underlying EBITDAF and underlying NPAT provide the most meaningful indicators of the Group’s underlying business performance. The directors utilise underlying NPAT as a measure to assess the performance of the segments. These earnings measures are referenced throughout the notes to the financial statements. A reconciliation to statutory earnings is provided in note 3. Underlying NPAT is statutory net profit after tax attributable to equity holders of the Company after excluding the after tax effect of unrealised marked to market changes in the fair value of financial instruments, impairment and gains / losses on onerous contracts and other significant items. Underlying NPAT excludes any profit or loss from associates. Significant items adjusted in deriving underlying NPAT are material items of revenue or expense that are unrelated to the underlying performance of the Group. All profit measures refer to continuing operations of the Group unless otherwise stated. R E W O P M R E 2 6 Notes to the Consolidated Financial Statements SECTION 1: FINANCIAL PERFORMANCE 1. EARNINGS PER SHARE (a) Basic (loss) / earnings per share From continuing operations attributable to the ordinary equity holders of the Company From discontinued operation Total basic (loss) / earnings per share attributable to the ordinary equity holders of the Company (b) Diluted (loss) / earnings per share From continuing operations attributable to the ordinary equity holders of the Company From discontinued operation Total basic (loss) / earnings per share attributable to the ordinary equity holders of the Company Consolidated 2018 2017 Cents per share (19.03) (13.83) (32.86) (18.52) (13.47) (31.99) 7.89 (8.33) (0.44) 7.66 (8.09) (0.43) (c) Underlying earnings / (loss) per share From continuing operations attributable to the ordinary equity holders of the Company 12.30 (6.59) (d) Reconciliations of earnings used in calculating earnings per share $’000 Basic (loss) / earnings per share Profit attributable to the ordinary equity holders of the Company used in calculating basic earnings per share: From continuing operations From discontinued operation Diluted (loss) / earnings per share Profit attributable to the ordinary equity holders of the Company used in calculating basic earnings per share: From continuing operations From discontinued operation (46,734) (33,968) 19,257 (20,330) (46,734) (33,968) 19,257 (20,330) Underlying profit / (loss) attributable to the ordinary equity holders of the Company from continuing operations 30,202 (16,095) (e) Weighted average number of shares used as the denominator Weighted average number used in calculating basic and underlying earnings per share Adjustments for calculation of diluted earnings per share: Long term incentive schemes Performance rights Weighted average number used in calculating diluted earnings per share Number of shares ‘000 245,580 244,161 6,066 653 7,162 - 252,299 251,323 Calculation methodology Basic earnings per share and underlying earnings per share are calculated by dividing the profit measure attributable to owners of the Company, by the weighted average number of ordinary shares outstanding during the financial year and excluding treasury shares. Diluted earnings per share are calculated the same way as basic earnings per share including the weighted average number of additional ordinary shares that would have been outstanding assuming the conversion of all dilutive potential ordinary shares. Options granted are considered to be potential ordinary shares and taken into account in the determination of diluted earnings per share. They are not included in the determination of basic earnings per share. t r o p e R l a u n n A 8 1 0 2 3 6 Notes to the Consolidated Financial Statements SECTION 1: FINANCIAL PERFORMANCE 2. DIVIDENDS PAID AND PROPOSED 2017 Final dividend paid 2018 Interim dividend paid 2018 Final dividend proposed Cents per share 3.5 3.5 4.0 Total amount $’000 8,943 9,001 10,217 Franking percentage Date of payment 100% 100% 100% 10-Oct-17 6-Apr-18 10-Oct-18 The final dividend proposed is subject to variations in the number of shares up to record date. This dividend has not been recognised as a liability as at 30 June 2018 and will be recognised in subsequent consolidated financial statements. Franking credits available at 30 June 2018 are $29.2m (2017: $10.9m). R E W O P M R E 4 6 3. SEGMENT REPORT Business Energy Australia Generation Assets Other Total $’000 2018 2017 2018 2017 2018 2017 2018 2017 External revenue to customers and other income 3,194,073 2,647,784 71,453 131,855 15,057 10,593 3,280,583 2,790,232 Internal segment revenue - - 20,045 13,932 7,202 4,681 27,247 18,613 Segment revenue and other income 3,194,073 2,647,784 91,498 145,787 22,259 15,274 3,307,830 2,808,845 Expenses EBITDAF Depreciation and amortisation Impairment expense Net fair value (loss) / gain on financial instruments designated at fair value through profit or loss (3,122,163) (2,594,425) (47,721) (104,077) (40,448) (32,158) (3,210,332) (2,730,660) 71,910 (9,840) (1,034) 53,359 43,777 41,710 (18,189) (16,884) (7,610) (13,409) (14,107) (6,975) (5,472) - - - 97,498 (30,224) (1,034) 78,185 (27,189) - (109,153) 50,929 - - - - (108,899) 36,276 (254) 14,653 Results from operating activities (47,863) 82,025 30,114 42,256 (25,164) (22,356) (42,913) 101,925 Share of net profit / (loss) of associates and joint ventures accounted for using the equity method Finance income Finance expenses (Loss) / profit before income tax Income tax benefit / (expense) (Loss) / profit from continuing operations Loss from discontinued operations (attributable to equity holders of the Company) Statutory loss for the year attributable to equity holders of the Company Underlying NPAT from continuing operations - - - - 195 (298) 195 (298) 2,154 2,746 562 468 (7,784) (15,488) (15,855) 384 (969) 397 (848) 76,987 15,188 26,869 (25,554) (23,105) (10,854) (56,563) 3,100 3,611 (27,311) (24,487) (66,929) 20,195 80,751 (61,494) (46,734) 19,257 (i) (33,968) (20,330) (80,702) (1,073) 30,202 (16,095) All segment activity takes place in Australia and the United States of America (i) Profit and loss information for the Business Energy US segment classified as a discontinued operation is reported through to the chief operational decision maker of the consolidated entity as shown in note 31. $’000 Statutory loss after tax attributable to equity holders of the Company Adjusted for the following items: Note 2018 (80,702) 2017 (1,073) Net unrealised change in fair value of financial instruments designated at fair value through profit or loss after tax 76,407 (35,650) Share of net (profit) / loss of associates and joint ventures accounted for using the equity method Loss from discontinued operation (attributable to equity holders of the Company) Other significant items Impairment of SME customer acquisition costs Tax benefit on other significant items Underlying NPAT continuing operations (i) Impairment of SME single site customer acquisition costs held for sale at 30 June 2018. (ii) Tax effect of the above other significant items. (195) 33,968 1,034 (310) 31 (i) (ii) 298 20,330 - - 30,202 (16,095) t r o p e R l a u n n A 8 1 0 2 5 6 Notes to the Consolidated Financial Statements SECTION 1: FINANCIAL PERFORMANCE 3. SEGMENT REPORT (CONTINUED) $’000 Assets Business Energy US(i) Business Energy Australia Generation Assets Other Note Total 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 Total segment assets - 145,413 673,050 899,581 436,792 429,303 80,082 88,171 1,189,924 1,562,468 Current and deferred tax assets Assets classified as held for sale Total assets Liabilities 2,974 13,850 31 167,235 - 1,360,133 1,576,318 Total segment liabilities - 143,576 641,319 405,829 227,602 230,464 32,529 34,101 901,450 813,970 Current and deferred tax liabilities Liabilities directly associated with assets classified as held for sale Total liabilities 57,095 196,468 31 152,088 - 1,110,633 1,010,438 (i) Balance sheet information for the Business Energy US segment classified as a discontinued operation is reported through to the chief operational decision maker of the consolidated entity as shown in note 31. Segment description An operating segment is a distinguishable component of an entity that engages in business activity from which it may earn revenues and incur expenses (including revenues and expenses relating to transactions with other segments of the same entity), and whose operating results are regularly reviewed by the chief operating decision maker to make decisions about resources to be allocated to the segment. Management has determined the operating segments based on reports reviewed by the Managing Director who is the chief operating decision maker for the Consolidated Entity. The Managing Director regularly receives financial information on the underlying profit of each operating segment so as to assess the ongoing performance of each segment and to enable a relevant comparison to budget and forecast underlying profit. Business segments: Products and services: Business Energy Australia Electricity sales to business customers in Australia Business Energy US Electricity sales to business and residential customers (FY2017 only) in the United States of America Generation Assets Gas-fired power generation assets and delivery of power generation solutions, from the initial concept through to development and operations Other Gas, Metering, Data Analytics, Lighting Solutions and Corporate The total of non-current assets other than financial instruments and deferred tax assets, broken down by location of the assets is $446.6m for Australia (2017: $440m) and $Nil for the United States (2017: $60.9m). Segment assets and liabilities are measured in the same way as in the financial statements. Both assets and liabilities are allocated based on the operations of the segment and the physical location of the asset. The Group’s current and deferred tax balances are not considered to be a part of a specific segment but are managed by the Group’s central corporate function. All revenue from generation assets and other operations is earned in Australia. R E W O P M R E 6 6 4. REVENUE Revenue is recognised when performance obligations under relevant customer contracts are completed. Performance obligations may be completed at a point in time or over time. In the following table revenue is disaggregated by major product or service line and by timing of revenue recognition. Revenue recognised in the discontinued Business Energy US segment is entirely generated within the US market whilst revenue recognised in all other segments is generated in Australia. Refer to note 31 for further details on the discontinued operations. No single customer amounts to 10% or more of the consolidated entity’s total external revenue for either the current or comparative period. $’000 Major product / service lines Sale of electricity Electricity generation Commodity product sales Energy solutions products and services Consulting fees Other revenue Timing of revenue recognition Business Energy Australia Generation Assets Other Total 2018 2017 2018 2017 2018 2017 2018 2017 3,068,351 2,495,553 - - 125,722 152,234 - - - - - - - 44,964 25,719 - 140 96 - 99,026 30,241 - - - - 14,368 264 2,139 - 116 - - - 7,548 785 1,623 3,068,351 2,495,553 44,964 151,441 14,368 140 212 99,026 182,475 7,548 1,049 3,762 3,194,073 2,647,787 70,919 131,670 14,484 9,956 3,279,476 2,789,413 Recognised at a point in time 125,722 152,234 70,919 131,670 Recognised over time 3,068,351 2,495,553 - - 13,424 1,060 7,239 210,065 291,143 2,717 3,069,411 2,498,270 3,194,073 2,647,787 70,919 131,670 14,484 9,956 3,279,476 2,789,413 Recognition and measurement i) Sale of electricity Revenue is recognised at the amount of consideration to which the Group is entitled, excluding amounts collected on behalf of third parties (i.e. duties and sales taxes). Using the practical expedient, the Group recognises revenue in respect to electricity sales over time as there is a right to invoice when the customers have consumed the performance obligation of electricity supply. Electricity sales revenue from customer sales contracts is recognised on measurement of electrical consumption (KWh) at the metering point, as specified in each contractual agreement, and is billed monthly in arrears. The transaction price is the contracted price for the electricity consumed during the period. When the consideration receivable is subject to variability, such as prompt payment discount or estimated meter reads, an assessment is performed to determine whether it is highly probable that the receivables or accrued income will be received. At each balance date, sales and receivables include an amount of sales delivered to customers but not yet billed and recognised as accrued income. ii) Electricity generation Electricity generation revenue is recognised from the generation of electricity at the point when the electricity has been supplied or the off- take performance obligation has been met and there will not be a significant reversal of revenue. Revenue received from off-take agreements provides a fixed revenue stream for the respective power station. Revenue on these contracts is recognised on a daily basis over the contract term. The transaction price is the contracted price for the electricity generated and sold during the period. At each balance date, sales and receivables include an amount of revenue for which performance obligations have been met under the respective contracts but have not yet settled. These amounts are recognised as accrued income. ERM Power has elected to apply the practical expedient available under AASB 15 to not disclose any future unsatisfied performance obligations under respective off-take agreements. iii) Energy solutions products and services Energy solutions products and services includes the sale of products and services such as lighting solutions, data analytics and energy monitoring, metering and demand response income. Revenue is apportioned to these contracts based on the estimated stand-alone selling price of goods or services provided. Revenue from customer sales contracts is recognised at the point that relevant performance obligations are satisfied, which will vary dependent on the product or service provided and may include product installation or access to energy management software. For any contracts that are recurring in nature such as annual subscriptions, an income in advance liability is recorded within accrued expenses for revenue received in advance and revenue is recognised over the term of the contract. t r o p e R l a u n n A 8 1 0 2 7 6 Notes to the Consolidated Financial Statements SECTION 1: FINANCIAL PERFORMANCE 4. REVENUE (CONTINUED) iv) Consulting fees and other revenue Revenue is apportioned to these contracts based on the estimated stand-alone selling price of goods or services provided. Consulting fee revenue and other income are recognised at the point that relevant performance obligations are satisfied. For any contracts that are recurring in nature such as annual licences, a liability is recorded for revenue received in advance and revenue is recognised over the term of the contract. v) Renewable energy certificates Revenue from the sale of renewable energy certificates is recognised when the relevant contractual performance obligations have been met. These performance obligations will generally include transfer of scheme certificates from the scheme registry of the seller to the scheme registry of the buyer. The stand-alone selling price for certificates sold is referenced within each sales contract. Sale of renewable energy certificates is included in commodity product sales. vi) Sale of gas Revenue from the sale of gas to wholesale market counterparties is recognised at the point at which the title passes to the buyer. Sale of gas revenue is included in commodity product sales. For further information on contract assets and liabilities, refer to notes 10 and 19. Key judgments and estimates Accrued income receivable Revenue from the sale of electricity is estimated where a customer invoice has not been raised at balance date. Where an invoice is raised shortly after balance date or customer meter data is available, this data is used to form the estimate of revenue. Where an invoice is not raised immediately after balance date and customer meter data is not available the revenue estimate is derived from an estimate of average daily electricity usage based on historical patterns as well as average pricing. Further information is contained in Note 10. Revenue recognised in relation to contract liabilities The following table shows how much of the revenue recognised in the current reporting period relates to carried-forward contract liabilities and how much relates to performance obligations that were satisfied in a prior year. Continuing operations Revenue recognised that was included in the contract liability balance at the beginning of the period Sale of electricity Electricity generation Energy solutions products and services Other revenue Consolidated 2018 $’000 2017 $’000 1,195 10 1,843 150 3,198 - - 315 10 325 R E W O P M R E 8 6 5. EXPENSES Continuing operations Cost of electricity sales Cost of electricity generation Cost of commodity products sold Employee benefits expense Share based payments Other expenses Included in the above employee benefits expense is: Defined contribution superannuation expense Consolidated 2018 $’000 2017 $’000 2,960,504 2,466,630 6,786 148,825 42,037 2,774 22,159 38,934 143,425 39,777 3,527 19,754 3,183,085 2,712,047 2,734 3,049 Recognition and measurement Cost of sales is recognised as those costs directly attributable to the goods or services sold and includes the costs of electricity, materials and associated distribution expenses. Electricity costs are based upon spot prices for electricity and the outcomes of derivative financial instruments entered into for the purpose of risk management (refer to note 22). Included within cost of sales are total net realised gains on the settlement of derivative financial instruments (2018: $91.5m, 2017: $573.5m). Employee benefits expense includes movement in recognition and measurement of related liabilities such as annual leave and long service leave. Refer to note 20. Share based payments are provided to employees via employee and executive equity plans. The fair value of options or shares issued to employees is recognised as an employee benefit expense with a corresponding increase in equity. The fair value is measured at grant date and recognised in the option reserve or share-based payment reserve over the period during which the employees become unconditionally entitled to the equity. When the shares are issued, or the options exercised, the value is transferred to contributed equity. Key judgments and estimates Share-based payment transactions The Company measures the cost of shares and options issued to employees and third parties by reference to the fair value of the equity instruments at the date at which they are granted. Details regarding the terms and conditions upon which the instruments were granted and methodology for determining fair value at grant date are available in note 33. The fair value of the equity instruments includes non-market vesting conditions. Management estimates the number of shares that are expected to be vested based on the probability of non-market vesting conditions being met. t r o p e R l a u n n A 8 1 0 2 9 6 Notes to the Consolidated Financial Statements SECTION 1: FINANCIAL PERFORMANCE 6. NET FAIR VALUE (LOSS) / GAIN ON FINANCIAL INSTRUMENTS DESIGNATED AT FAIR VALUE THROUGH PROFIT AND LOSS Continuing operations Unrealised Electricity derivative contracts Hedge ineffectiveness Consolidated 2018 $’000 2017 $’000 (109,153) - (109,153) 51,009 (80) 50,929 Recognition and measurement The Group accounts for certain derivative financial instruments such as cash flow hedges with corresponding unrealised fair value movements recognised in the cash flow hedge reserve. Any unrealised gain or loss on other instruments that are not hedge accounted and any ineffective portion of hedge accounted instruments is recognised directly in profit or loss. Refer note 13 for further information on which derivative financial instruments are not hedge accounted. Key judgments and estimates Designation of instruments The designation of instruments as either held for trading or hedging may affect the amount of fair value gains and losses recognised in profit and loss. Fair value movements on instruments held for trading are not deferred within the cash flow hedge reserve. Further information on the designation of financial instruments is contained in note 13. Valuation of derivative financial instruments The valuation of financial instruments may affect the amount of fair value movements recognised in profit and loss. Further information on the valuation of financial instruments is contained in note 23. R E W O P M R E 0 7 7. NET FINANCE EXPENSE Continuing operations Finance income Interest income Finance costs Borrowing costs – lease liabilities Borrowing costs – bank loans Borrowing costs – receivables financing facility Borrowing costs – convertible notes Other borrowing costs Consolidated 2018 $’000 2017 $’000 3,100 3,100 733 11,542 5,145 3,937 5,954 27,311 3,611 3,611 831 12,054 3,418 3,799 4,385 24,487 Recognition and measurement Interest revenue and expenses are recognised on a time proportional basis using the effective interest rate method applicable to financial assets and liabilities. Other borrowing costs includes bank guarantee charges associated with the Group’s Australian electricity retailing operation. t r o p e R l a u n n A 8 1 0 2 1 7 Notes to the Consolidated Financial Statements SECTION 1: FINANCIAL PERFORMANCE 8. INCOME TAX (a) Income tax (benefit) / expense Income tax comprises: Current tax expense Deferred tax (benefit) / expense Adjustment to current and deferred tax of prior periods Income tax (benefit) / expense Income tax (benefit) / expense is attributable to: (Loss) / profit from continuing operations Loss from discontinued operations (b) Numerical reconciliation of prima facie tax benefit to prima facie tax (Loss) / profit from continuing operations Loss from discontinued operations Income tax (benefit) / expense calculated at 30% Other income taxes Net effect of expenses / (income) that are not deductible / (non-assessable) in determining taxable profit (excluding Clean Energy Regular shortfall charge) Clean Energy Regulator shortfall (refund) / charge Write-down of US deferred tax balance Adjustment to deferred tax of prior periods Difference in overseas tax rates Change in overseas tax rate Income tax (benefit) / expense (c) Amounts recognised directly in other comprehensive income Increase in equity due to current and deferred amounts charged directly to equity during the period: Net tax effect of amounts charged to cash flow hedge reserve Net tax effect of amounts charged to share capital Note Consolidated 2018 $’000 2017 $’000 31 31 (i) 21/(ii) (iii) 8,041 (15,663) (277) (7,899) (20,195) 12,296 (7,899) (66,929) (21,672) (88,601) (26,580) 949 301 (388) 10,279 (277) 211 7,606 (7,899) 32,971 20,846 (85) 53,732 61,494 (7,762) 53,732 80,751 (28,092) 52,659 15,798 205 1,919 37,050 - (85) (1,155) - 53,732 95,902 (49,960) 28 - 95,930 (49,960) (i) In 2017, the Company took the commercial decision to incur a non-deductible charge of $65 per certificate in lieu of surrendering 1.9m large scale generation certificates. The total cost was $123m before tax. In 2018, the Company surrendered a parcel of large scale generation certificates and received a non-assessable refund of the previous charge of $1.3m before tax. (ii) Estimated non-recoverability of US deferred tax losses. (iii) Change in US federal tax rate from 35% to 21% effective from 1 January 2018. R E W O P M R E 2 7 8. INCOME TAX (CONTINUED) Recognition and measurement Income tax or income tax benefit for the period is the tax payable on the current period’s taxable income based on the prevailing income tax rate adjusted by changes in deferred tax assets and liabilities attributable to temporary differences and to unused tax losses. Deferred income tax is provided in full, using the liability method, on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the consolidated financial statements. However, deferred income tax is not accounted for if it arises from initial recognition of an asset or liability in a transaction other than a business combination that at the time of the transaction affects neither accounting nor taxable profit or loss. Current and deferred tax is recognised in profit or loss, except to the extent that it relates to items recognised in other comprehensive income or directly in equity. In this case, the tax is also recognised in other comprehensive income or directly in equity, respectively. Key judgments and estimates The current income tax charge is calculated on the basis of tax laws enacted or substantively enacted at the end of the reporting period in the countries where the Company’s subsidiaries and associates operate and generate taxable income. Management periodically evaluates positions taken in tax returns with respect to situations in which applicable tax regulation is subject to interpretation. It establishes provisions where appropriate on the basis of amounts expected to be paid to the tax authorities. Deferred income tax is determined using tax rates (and laws) that have been enacted or substantially enacted by the balance date and are expected to apply when the related deferred income tax asset is realised or the deferred income tax liability is settled. 9. CASH FLOW INFORMATION a) Reconciliation of cash flows from operating activities Net loss after tax Adjustments for: Depreciation and amortisation of non-current assets Impairment expense Share based payment expense Net unrealised fair value losses / (gains) on financial instruments and inventory Gain on the sale of discontinued operations Share of (profits) / loss of associates Loss on the sale of non-current assets Net exchange differences Finance costs Transfers to provisions: Employee entitlements Changes in operating assets and liabilities: Increase in trade and other receivables Increase in other assets Increase in inventories Increase in deferred tax assets recognised in profit or loss Changes in variation margin account (Decrease) / increase in deferred tax liabilities recognised in profit or loss (Decrease) / increase in current tax liability Increase in trade and other payables Net cash (used in) / provided by operating activities Consolidated 2018 $’000 (80,702) 46,911 1,034 2,774 99,582 - (195) 137 (665) 2017 $’000 (1,073) 38,404 - 3,527 (34,541) (10,851) 298 - 96 42,056 31,091 582 256 (37,446) (9,436) (37,737) (8,459) (118,723) (5,543) (21,062) 84,113 (42,779) (40,936) (2,963) (30,725) (169) 69,181 21,015 18,403 90,679 151,692 t r o p e R l a u n n A 8 1 0 2 3 7 Notes to the Consolidated Financial Statements SECTION 1: FINANCIAL PERFORMANCE 9. CASH FLOW INFORMATION (CONTINUED) b) Net debt reconciliation This section sets out an analysis of net debt and the movements in net debt for each of the periods presented. Consolidated Cash and cash equivalents – continuing operations Cash and cash equivalents – discontinued operations Borrowings – repayable within one year Borrowings – limited recourse – repayable within one year Borrowings – limited recourse – repayable after one year Net (debt) / cash Cash and cash equivalents Gross debt – fixed interest rates Gross debt – variable interest rates Net (debt) / cash 2018 $’000 227,636 12,822 (150,831) (8,904) (176,567) (95,844) 240,458 (126,750) (209,552) (95,844) Other assets Liabilities from financing activities Cash $’000 Borrowings due within 1 year $’000 Borrowings due after 1 year $’000 2017 $’000 244,616 - - (8,264) (180,653) 55,699 244,616 (131,874) (57,043) 55,699 Total $’000 55,699 (149,601) (1,942) (180,653) 5,904 (1,818) (176,567) (95,844) Net debt as at 30 June 2017 Cash flows Other non-cash movements Net debt as at 30 June 2018 244,616 (4,158) - 240,458 (8,264) (151,347) (124) (159,735) R E W O P M R E 4 7 Notes to the Consolidated Financial Statements SECTION 2: OPERATING ASSETS AND LIABILITIES 10. TRADE AND OTHER RECEIVABLES AT AMORTISED COST The majority of trade and other receivables relate to electricity sales customers. Trade receivables are non-interest bearing and are generally 14 to 30 day terms. Current Trade and other receivables Accrued income Consolidated 2018 $’000 2017 $’000 38,888 281,363 320,251 66,906 294,041 360,947 Recognition and measurement All trade and other debtors are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method. The effective interest method is a method of calculating the amortised cost of a financial asset and of allocating interest income over the relevant period. The effective interest rate is the rate that discounts estimated future cash receipts (including all transaction costs and other premiums or discounts) through the expected life of the financial asset, or, where appropriate, a shorter period. Collectability is reviewed on an ongoing basis. For trade receivables, the Company applies the simplified approach to providing for expected credit losses prescribed by AASB 9, which requires the use of the lifetime expected loss provision for all trade receivables. The amount of the impairment loss is recognised in the income statement. Accrued income receivable represents electricity amounts due to be invoiced after 30 June 2018 and wholesale counterparty settlements due to be accrued and received after 30 June 2018. Key judgments and estimates Accrued income receivable Accrued electricity sales revenue requires estimates of average daily usage based on historical patterns as well as average pricing and consumption pattern estimates where no actual meter data is available. A large portion of accrued income receivable is measured based on actual billed electricity in the following month whilst a smaller portion is based on estimated meter data where the customer meter is read less frequently. Credit risk Credit risk refers to the loss that would occur if a debtor or other counterparty fails to perform under its contractual obligations. The carrying amounts of trade and other receivables recognised at balance date best represents the Group’s maximum exposure to credit risk at balance date. The Group seeks to limit its exposure to credit risks as follows: • • • conducting appropriate due diligence on counterparties before entering into arrangements with them; depending on the outcome of the credit assessment, obtaining collateral with a value in excess of the counterparties’ obligations to the Group – providing a ‘margin of safety’ against loss; and for derivative counterparties, using primarily high credit quality counterparties, in addition to utilising ISDA master agreements with derivative counterparties in order to limit the exposure to credit risk. The credit quality of all financial assets is consistently monitored in order to identify any potential adverse changes. t r o p e R l a u n n A 8 1 0 2 5 7 Notes to the Consolidated Financial Statements SECTION 2: OPERATING ASSETS AND LIABILITIES 10. TRADE AND OTHER RECEIVABLES AT AMORTISED COST (CONTINUED) Concentrations of credit risk The Group minimises concentrations of credit risk in relation to debtors by undertaking transactions with a large number of customers from across a broad range of industries within the business segments in which the Group operates, such that there are no significant concentrations of credit risk within the Group at balance date. Credit risk to trade debtors is managed through setting normal payment terms of up to 30 days and through continual risk assessment of debtors with material balances. Credit risk to electricity debtors is managed through system driven credit management processes. The process commences after due date. For some debtors the Group may also obtain security in the form of guarantees, deeds of undertaking, or letters of credit which can be called upon if the counterparty is in default under the terms of the agreement. The Company applies the simplified approach to providing for expected credit losses prescribed by AASB 9, which permits the use of the lifetime expected loss provision for all trade receivables. The expected credit losses also incorporates forward looking information. The loss allowance provision as at 30 June 2018 is determined as follows: Total $’000 < 30 days $’000 31-60 days $’000 61-120 days $’000 > 120 days $’000 2018 Consolidated Trade Other(i) Trade Other(i) Trade Other(i) Trade Other(i) Expected loss rate Gross carrying amount Loss allowance provision(ii) Net receivables Accrued income 0% - 5% 37,087 (667) 41,531 (2,643) 38,888 36,420 281,363 281,363 2017 Consolidated Expected loss rate Gross carrying amount Loss allowance provision(ii) Net receivables Accrued income 0% - 8% 63,938 (1,265) 62,673 70,324 (3,418) 66,906 294,041 294,041 - 182 - 182 - - 497 - 497 - 10% 1,319 (131) 1,188 - 16% 2,659 (418) 2,241 - - - - - - - 23 - 23 - 40%-90% - Up to 100% 955 (463) 492 - - - - - 1,988 (1,382) 606 - 50%-90% - Up to 100% 1,132 (398) 734 - 46 - 46 - 1,428 (1,337) 91 - - - - - - - 601 - 601 - (i) Other receivables are neither past due or impaired and relate principally to counterparty receivables and employee shareholder loans which are subject to loan deeds. (ii) Of the above loss allowance provision $2.6m (2017: $3.4m) relate to receivables arising from contracts with customers. R E W O P M R E 6 7 11. INVENTORIES Work in progress Stock on hand Renewable energy certificates – at cost Note Consolidated 2018 $’000 246 914 67,150 11,993 77 1,382 81,762 2017 $’000 531 485 38,115 1,415 96 1,615 42,257 Renewable energy certificates – at fair value less cost to sell (i) Gas in storage Diesel fuel (i) Renewable energy certificates designated as commodity broker trader inventory are measured at fair value less costs to sell. Recognition and measurement Renewable energy certificates Renewable energy certificates held by the Group are accounted for as commodity inventories. The Group participates in the purchase and sale of a range of renewable energy certificates, including both mandatory and voluntary schemes. Purchased renewable energy certificates are initially recognised at cost within inventories on settlement date. Subsequent measurement is at the lower of cost or net realisable value, with losses arising from changes in realisable value being recognised in the income statement in the period of the change. Renewable energy certificates held for trading are held at fair value less costs to sell. Other inventory Stock, materials and work in progress are stated at the lower of cost and net realisable value. Cost comprises direct materials, direct labour and an appropriate proportion of variable and fixed overhead expenditure, the latter being allocated on the basis of normal operating capacity. Cost includes the reclassification from equity of any gains or losses on qualifying cash flow hedges relating to purchases of raw material but excludes borrowing costs. Costs are assigned to individual items of inventory on the basis of weighted average costs. Costs of purchased inventory are determined after deducting rebates and discounts. Net realisable value is the estimated selling price in the ordinary course of business less the estimated costs of completion and the estimated costs necessary to make the sale. Key judgments and estimates Renewable energy certificates held for trading Renewable energy certificates that are designated as held for trading are initially recognised at cost and are subsequently recognised at fair value with movements in fair value taken up through profit and loss in the net fair value gain on financial instruments designated at fair value through profit and loss line until settlement at which time the gain or loss is recognised in cost of goods sold. Certificates are designated at the initial trade date on a deal by deal basis and segregated from other certificates held for the purposes of surrender under applicable renewable energy schemes. t r o p e R l a u n n A 8 1 0 2 7 7 Notes to the Consolidated Financial Statements SECTION 2: OPERATING ASSETS AND LIABILITIES 12. OTHER ASSETS Prepayments Security and other deposits Other Consolidated 2018 $’000 4,119 10,185 297 14,601 2017 $’000 3,985 1,573 622 6,180 13. DERIVATIVE FINANCIAL INSTRUMENTS The Group is party to derivative financial instruments in the normal course of business acquired in order to manage exposure to fluctuations in electricity prices and interest and foreign exchange rates in accordance with the Group’s financial risk management policies. Current assets Electricity and commodity derivatives Foreign exchange derivatives Non-current assets Electricity and commodity derivatives Current liabilities Electricity and commodity derivatives Non-current liabilities Electricity and commodity derivatives Interest rate swaps Recognition and measurement Consolidated 2018 $’000 2017 $’000 73,127 325,131 - 30 73,127 325,161 25,968 25,968 28,239 28,239 55,702 29,481 85,183 81,445 81,445 33,889 33,889 33,641 33,812 67,453 Derivatives financial instruments are initially recognised at fair value on the date a derivative contract is entered into and are subsequently re- measured to their fair value at the end of each reporting period. The accounting for subsequent changes in fair value depends on whether the derivative is designated as a hedging instrument, and if so, the nature of the item being hedged and the type of hedge relationship designated. The gain or loss from re-measurement of hedging instruments at fair value is recognised in other comprehensive income and deferred in equity in the hedging reserve, to the extent that the hedge is effective. It is reclassified into profit or loss when the hedged interest expense is settled. Certain derivative instruments do not qualify for hedge accounting. The change in the fair value of any derivative instrument that does not qualify for hedge accounting is recognised immediately in profit or loss. Any realised gains or losses on settlement of derivatives that do not qualify for hedge accounting are recognised immediately in profit and loss and are included within cost of sales regardless of the original settlement date of the instrument. Derivatives that are not hedge accounted include futures, bilateral written options, market traded caps and swaps and any derivative held for trading purposes or to manage renewable certificate price risk including forward purchase agreements held for trading. All derivatives used in the Group’s US Business Energy operations are not hedge accounted. R E W O P M R E 8 7 13. DERIVATIVE FINANCIAL INSTRUMENTS (CONTINUED) Recognition of day one gain or loss on derivative financial instruments Evidence of fair value of an investment at initial recognition is often provided by the transaction price, unless the fair value of the instrument is evidenced by comparison with other observable current market transactions in the same instrument, or based on a valuation technique whose variables include only data from observable markets. Such financial instruments are initially recognised at the transaction price which is the best indicator of fair value, although the market value derived by independent valuers may differ. The difference between the transaction price and the market value (the day one gain or loss), is not recognised immediately for accounting purposes in profit or loss and is instead recognised through profit or loss progressively as the instrument is settled. Any subsequent measurement of the instrument excludes the balance of the deferred day one gain or loss. Key judgments and estimates Fair value of financial instruments The fair value of financial assets and financial liabilities are estimated for recognition and measurement and for disclosure purposes. Management uses its judgement in selecting appropriate valuation techniques for financial instruments not quoted in active markets. Valuation techniques commonly used by market practitioners are applied. For derivative financial instruments, assumptions are made based on quoted market rates adjusted for specific features of the instrument. Other financial instruments are valued using a discounted cash flow analysis based on assumptions supported, where possible, by observable market prices and rates. Refer to note 23 for further details of valuation methods used by the Group to determine fair value. 14. HEDGE ACCOUNTING Contracts are entered into with individual parties in the normal course of business in order to economically hedge exposure to fluctuations in electricity prices, foreign currency and interest rates. These derivative instruments may meet the requirements for hedge accounting. The instruments include OTC swaps, options, swaptions, caps and other risk management instruments. Settlement of the contracts require exchange of cash for the difference between the contracted and spot market prices. The contracts are measured at fair value and the resultant gains or losses that effectively hedge designated risk exposures are deferred within the cash flow reserve. Electricity derivatives used for hedging The below carrying values represent the total value of hedge instruments used to hedge electricity price risk recognised on the Group’s balance sheet together with maturity of these instruments and associated nominal volume. The value of these instruments excludes the ineffective portion that has not been recognised in the cash flow hedge reserve. Net asset / (liability) 12 months or less More than 12 months Assets Carrying value(i) Liabilities Carrying value(i) Nominal hedge volume(ii) 2018 $’000 63,763 13,936 77,699 2017 $’000 316,631 69,614 386,245 2018 $’000 (12,149) (28,093) (40,242) 2017 $’000 (10,157) (15,219) (25,376) 2018 TWh 14 3 17 2017 TWh 12 4 16 (i) Carrying value of hedging instruments only. (ii) Nominal hedge volumes exclude volumes for other instruments that provide an economic hedge but are not hedge accounted for, such as exchange based instruments and instruments used in the Group’s US operations. The Group uses cash flow hedges to mitigate the risk of variability in electricity prices. The instruments that are hedge accounted include OTC swaps, options, swaptions, caps and other eligible risk management instruments used in the Groups Australian business energy operations. Hedge rates for these instruments vary by product type, time period and region and range from $10 to $300 per MWh. Instruments held for trading, exchange traded instruments (such as futures contracts), written options and all instruments related to renewable energy certificates and our US operations are not hedge accounted. The above nominal hedge volumes exclude volumes associated with these instruments. t r o p e R l a u n n A 8 1 0 2 9 7 Notes to the Consolidated Financial Statements SECTION 2: OPERATING ASSETS AND LIABILITIES 14. HEDGE ACCOUNTING (CONTINUED) The movement in the hedged items for the year ended 30 June 2018 was ($319.7m) (2017: $166.6m). The movement in hedge instruments recognised in reserves for the year ended 30 June 2018 was ($319.7m) (2017: $166.5m). There was no hedge ineffectiveness recognised for the year ended 30 June 2018 (2017: $0.1m). The effective portion of changes in the fair value of derivatives that are designated and qualify as cash flow hedges are recognised in the cash flow hedge reserve within equity, limited to the cumulative change in fair value of the hedged item on a present value basis from the inception of the hedge. Effectiveness is assessed against forecast electricity purchase requirements. Where the portfolio volume of the cash flow hedge contracts is in excess of forecast electricity purchase requirements for a particular time period an amount of ineffectiveness is recognised immediately in profit or loss. During the year ended 30 June 2018 amounts accumulated to the cash flow hedge reserve of $88.0m (2017: $453.2m) were settled and recognised as a gain in profit and loss. Interest rate swaps used for hedging The Neerabup partnership has limited recourse, variable interest rate project finance in place. This variable interest has been swapped into fixed. Swaps currently in place for the Neerabup partnership cover approximately 97% (2017: 97%) of the variable loan principal outstanding and are timed to expire as each loan repayment falls due as set out below. The fixed interest rate is 7.189% (2017: 7.189%) and the variable rate is 1.1% above the BBSY rate which at the end of the reporting period was 1.95% (2017: 2.05%). There was no hedge ineffectiveness in the current or prior year and the movement of the fair value of the hedged item and instrument deferred in the hedge reserve was $4.3m (2017: $7.8m). Swap liabilities 12 months or less 1-2 years 2-5 years More than 5 years Consolidated 2018 $’000 6,272 5,782 13,278 4,149 29,481 2017 $’000 6,870 6,033 13,918 6,991 33,812 The above table indicates the periods in which the cash flows associated with cash flow hedges are expected to impact profit or loss and the fair value of the related hedging instruments. The notional amount of debt covered by the interest rate swap in place at 30 June 2018 was $126.8m (2017: $131.8m). During the year ended 30 June 2018 amounts accumulated to the cash flow hedge reserve of $6.8m (2017: $7.0m) were settled and recognised in profit and loss. Recognition and measurement of derivatives hedge accounted The full fair value of a hedging derivative is classified as a non-current asset or liability when the remaining maturity of the hedged item is more than 12 months; it is classified as a current asset or liability when the remaining maturity of the hedged item is less than 12 months. Trading derivatives are classified as a current asset or liability. The effective portion of changes in the fair value of derivatives that are designated and qualify as cash flow hedges is recognised in the cash flow hedge reserve within equity, limited to the cumulative change in fair value of the hedged item on a present value basis from the inception of the hedge. The gain or loss relating to the ineffective portion is recognised immediately in profit or loss. Gains or losses relating to the effective portion of the change in intrinsic value of the option contracts are recognised in the cash flow hedge reserve within equity. The changes in the time value of the option contracts that relate to the hedged item (‘aligned time value’) are recognised within other comprehensive income in the costs of hedging reserve within equity. Amounts accumulated in equity are reclassified in the periods when the hedged item affects profit or loss. When a hedging instrument expires, or is sold or terminated, or when a hedge no longer meets the criteria for hedge accounting, any cumulative deferred gain or loss and deferred costs of hedging in equity at that time remains in equity until the forecast transaction occurs, resulting in the recognition of a non-financial asset such as inventory. When the forecast transaction is no longer expected to occur, the cumulative gain or loss and deferred costs of hedging that were reported in equity are immediately reclassified to profit or loss. If the hedge ratio for risk management purposes is no longer optimal but the risk management objective remains unchanged and the hedge continues to qualify for hedge accounting, the hedge relationship will be rebalanced by adjusting either the volume of the hedging instrument or the volume of the hedged item so that the hedge ratio aligns with the ratio used for risk management purposes. Any hedge ineffectiveness is calculated and accounted for in profit or loss at the time of the hedge relationship rebalancing. R E W O P M R E 0 8 15. PROPERTY, PLANT AND EQUIPMENT Consolidated 2018 Cost Accumulated depreciation and impairment Net carrying amount at 30 June 2018 Note Land $’000 Capital work in progress $’000 Plant and equipment $’000 Furniture, fittings and improvements $’000 Total $’000 22,963 (447) 22,516 669 - 669 508,601 (146,921) 361,680 14,585 (8,768) 5,817 546,818 (156,136) 390,682 Opening net carrying amount at 1 July 2017 22,516 5,549 359,141 4,180 391,386 Exchange differences Additions Disposals Transfers Depreciation Assets included in a disposal group classified as held for sale 31 - - - - - - - 566 - (5,446) - - 9 12,254 (315) 5,005 (13,926) (488) 22 3,336 (15) 441 (1,866) (281) 31 16,156 (330) - (15,792) (769) Closing net carrying amount at 30 June 2018 22,516 669 361,680 5,817 390,682 Consolidated 2017 Cost Accumulated depreciation and impairment Net carrying amount at 30 June 2017 Note Land $’000 Capital work in progress $’000 Plant and equipment $’000 Furniture, fittings and improvements $’000 Total $’000 22,963 (447) 22,516 5,549 492,532 - (133,391) 5,549 359,141 11,483 (7,303) 4,180 532,527 (141,141) 391,386 Opening net carrying amount at 1 July 2016 22,516 5,288 358,644 4,818 391,266 Exchange differences Additions Disposals Transfers Depreciation - - - - - Closing net carrying amount at 30 June 2017 22,516 Capital work in progress relates to capitalised costs for power station projects. - 5,442 - (5,181) - 5,549 (5) 9,897 (55) 5,095 (14,435) 359,141 (5) 803 - 24 (10) 16,142 (55) (62) (1,460) 4,180 (15,895) 391,386 One of the Group’s current generation assets, the Neerabup power station, is project financed by limited recourse debt, meaning the security of project lenders does not extend beyond the particular generation asset. The Group also raised funds for its equity investment in the Neerabup power station by issuing notes in 2008. Those notes are limited-recourse to the Group’s interest in the Neerabup power station. Refer note 25 for details regarding recourse and limited recourse borrowings of the Group. t r o p e R l a u n n A 8 1 0 2 1 8 Notes to the Consolidated Financial Statements SECTION 2: OPERATING ASSETS AND LIABILITIES 15. PROPERTY, PLANT AND EQUIPMENT (CONTINUED) Recognition and measurement Items of property, plant and equipment are initially measured at historical cost less depreciation. Historical cost includes expenditure that is directly attributable to the acquisition of the items. Cost may also include transfers from equity of any gains / losses on qualifying cash flow hedges of foreign currency purchases of property, plant and equipment. 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 repairs and maintenance expenses are charged to the income statement during the financial period in which they are incurred. Assets that are subject to depreciation 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 its value in use. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash inflows. Capital work in progress comprises costs incurred to date on construction of power generation plants. Asset residual values and useful lives are reviewed and adjusted if appropriate at each balance date. Gains and losses on disposals are determined by comparing the proceeds to the carrying amount. These are included in the income statement. Borrowing costs incurred for the construction of any qualifying asset are capitalised during the period of time that is required to complete and prepare the asset for its intended use or sale. Other borrowing costs are expensed. The capitalisation rate used to determine the amount of borrowing costs to be capitalised to each project is the effective interest rate applicable to the specific borrowings at a project level during the year. Key judgments and estimates Depreciation Land and capital work in progress are not depreciated. Depreciation on the other assets is calculated using the straight-line method to allocate their cost, net of their residual values, over their estimated useful lives, as follows: Leasehold improvements the lesser of the remaining lease term and the life of the asset Motor vehicles 8 years Power stations and power station components 1 – 50 years Other plant and equipment IT Equipment Furniture and fittings 1 – 15 years 1 – 3 years 1 – 10 years R E W O P M R E 2 8 16. INTANGIBLE ASSETS Consolidated Note Goodwill $’000 Capital work in progress $’000 Software internally generated $’000 Software and other $’000 Customer acquisition costs $’000 Total $’000 2018 Cost Accumulated depreciation and impairment Net carrying amount at 30 June 2018 6,454 - 6,454 Opening net carrying amount at 1 July 2017 26,806 Current period trailing commission sales and additions (i) Exchange differences Additions Disposals Transfer Amortisation Impairment expense Assets included in a disposal group classified as held for sale (ii) 31/(iii) - 829 - - - - - (21,181) 1,478 - 1,478 91 - - 1,428 - (41) - - - 27,913 (12,215) 15,698 5,224 (3,412) 1,812 13,521 3,258 - - 5,606 - 100 - 74 506 (167) (59) 29,853 (16,829) 13,024 45,702 36,401 1,825 - - - (3,529) (1,159) (23,488) - - - (1,034) (641) (46,382) (68,204) Closing net carrying amount at 30 June 2018 6,454 1,478 15,698 1,812 13,024 38,466 Consolidated 2017 Cost Accumulated depreciation and impairment Net carrying amount at 30 June 2017 Note Goodwill $’000 Capital work in progress $’000 Software internally generated $’000 Software and other $’000 Customer acquisition costs $’000 Total $’000 26,806 - 26,806 91 - 91 22,204 (8,683) 13,521 7,237 (3,979) 3,258 71,188 (25,486) 45,702 Opening net carrying amount at 1 July 2016 32,568 1,304 12,501 2,026 Current period trailing commission sales and additions (i) - Exchange differences Additions Transfers Amortisation (807) - - - Assets included in a disposal group classified as held for sale and other disposals 31 (4,955) Closing net carrying amount at 30 June 2017 26,806 (i) Refer to note 20 for corresponding provision movement. - - 8 (1,221) - - 91 - - 3,813 292 - (50) 1,330 991 30,642 31,850 (1,060) - - (3,085) (1,039) (15,488) - - (242) 13,521 3,258 45,702 89,378 (ii) (iii) Impairment of the SME single site customer acquisition costs held for sale at 30 June 2018. The $68.2m intangible assets held for sale reflects management’s decision to sell the US business Source Power & Gas ($64.8m) and the single site SME customer contracts from the Business Energy Australia operations ($3.4m). Amortisation of intangible assets is included in depreciation and amortisation expense in the income statement. t r o p e R l a u n n A 8 1 0 2 3 8 70,922 (32,456) 38,466 89,378 36,401 2,728 7,540 (167) - (28,176) (1,034) 127,526 (38,148) 89,378 79,041 31,850 (1,917) 5,151 62 (19,612) (5,197) Notes to the Consolidated Financial Statements SECTION 2: OPERATING ASSETS AND LIABILITIES 16. INTANGIBLE ASSETS (CONTINUED) Recognition and measurement Goodwill Goodwill on acquisitions of subsidiaries is included in intangible assets. Goodwill on acquisitions of associates is included in investments in associates. Goodwill is not amortised but it is tested for impairment annually or more frequently if events or changes in circumstances indicate that it might be impaired, and is carried at cost less accumulated impairment losses. Gains and losses on the disposal of an entity include the carrying amount of goodwill relating to the entity sold. Goodwill is allocated to cash-generating units for the purpose of impairment testing. The allocation is made to those cash-generating units or groups of cash-generating units that are expected to benefit from the business combination in which the goodwill arose, identified according to operating segments. Software Computer software is either purchased or developed within the organisation to support business operations and generate customer revenue. Software assets are recorded at cost less accumulated amortisation and impairment losses. Customer acquisition costs The direct costs of establishing customer contracts are recognised as an asset when the customer contract is expected to provide a future economic benefit to the Group. Direct costs are amortised over an average contract term. In the event that a customer contract is not fulfilled and direct costs are not recoverable from the channel partner, a provision for impairment is recognised. Customer contracts acquired in a business combination are recognised at fair value at the acquisition date. They have a finite useful life and are subsequently carried at cost less accumulated amortisation and impairment losses. Customer contracts that are acquired through a trailing commission agreement have a corresponding provision liability recognised. The provision liability is measured against forecast payments required and is discounted at a risk free rate. Key judgments and estimates Purchase price allocation AASB 3 Business Combinations requires the recognition of fair value estimates of assets and liabilities acquired. By the nature of these estimates, judgements are made on the allocation of the purchase consideration. Goodwill is not amortised. Amortisation Amortisation of intangible assets is calculated using the straight-line method to allocate their cost, net of their residual values, over their estimated useful lives, as follows: Software 3 – 10 years Customer acquisition costs (Australia) Average contract term of 2 years (2017: 2 years) Customer acquisition costs (United States) Over individual contract term as trailing fee paid R E W O P M R E 4 8 17. IMPAIRMENT OF NON-FINANCIAL ASSETS The Group tests property, plant and equipment, intangibles and goodwill for impairment: • • • at least annually for indefinite life intangibles and goodwill; and where there is an indication that the asset may be impaired (which is assessed at least each reporting date); or where there is an indication that previously recognised impairment (on assets other than goodwill) may have changed. If the asset does not generate independent cash inflows and its value in use cannot be estimated to be close to its fair value, the asset is tested for impairment as part of the cash-generating unit (CGU) to which it belongs. Assets are impaired if their carrying value exceeds their recoverable amount. The recoverable amount of an asset or CGU is determined as the higher of its fair value less costs of disposal or value in use. At 30 June 2018 the Group did not have any indefinite life intangible assets. The Group had goodwill of $27.6m of which 77% related to the Group’s US operations, which are classified as held for sale. Refer to note 31 for further details. Recognition and measurement 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 its value in use. Impairment losses recognised for goodwill are not reversed. Impairment losses recognised in prior periods for other assets are assessed at each reporting date for any indications that the impairment loss has decreased or may no longer exist. The impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount of the asset and is reversed only to the extent that the carrying amount of the asset does not exceed the carrying amount that would have been determined, net of amortisation or depreciation, had no impairment loss been recognised. There were no material reversals of impairment in the current or prior year. Key judgments and estimates At 30 June 2018 the Group has tested goodwill for impairment and made critical judgements with respect to assumptions used in the value in use assessment. These assumptions are set out below. CGU Goodwill allocation Pre-tax discount rate Years of cash flows included Cumulative average growth rate(i) Terminal growth rate Energy Solutions(ii) 2018 $’000 6,454 2017 $’000 6,454 2018 % 2017 % 13.3% 14.9% 2018 years 5 2017 years 5 2018 % 15% 2017 % 39.2% 2018 % 3% 2017 % 2.5% (i) Cumulative average growth rate is based on revenue. (ii) Energy Solutions CGU goodwill includes the goodwill arising on the acquisition of Lumaled Pty Ltd and Greensense Pty Ltd. The acquisitions of these businesses were completed in the first half of 2016. Management have utilised a value in use model to test goodwill for impairment at 30 June 2018 for the CGU. In assessing value in use, the estimated future cash flows are discounted to their present value using a discount rate that reflects current market assessments of the time value of money and the risks specific to the asset or CGU. Sensitivity analysis on reasonably possible changes to the discount rates or growth rates would result in an outcome where impairment would be required for the Energy Solutions goodwill as carrying value is equal to fair value. Directors and management have considered the likelihood of this change and have not updated the impairment calculation given the strong revenue growth for the current year, early lifecycle stage of the Energy Solutions business and availability of capital to fund organic growth. t r o p e R l a u n n A 8 1 0 2 5 8 Notes to the Consolidated Financial Statements SECTION 2: OPERATING ASSETS AND LIABILITIES 18. LEASE ASSETS AND LIABILITIES Right of use lease assets Cost Accumulated depreciation and impairment Net carrying amount at 30 June 2018 Adoption of AASB 16 Leases Opening net carrying amount at 1 July Exchange differences Additions Amortisation Classified as held for sale Closing net carrying amount at 30 June Note Consolidated 2018 $’000 15,876 (5,352) 10,524 - 14,381 37 39 (2,943) (990) 10,524 2017 $’000 17,278 (2,897) 14,381 14,408 - (23) 2,893 (2,897) - 14,381 31 The Group leases office premises in Brisbane, Sydney, Melbourne, Perth, Newcastle and Houston. Income from the sublease of the Group’s office premises for the year ended 30 June 2018 is $431,110 (2017: $385,277). Lease liabilities Current Lease liabilities Non-current Lease liabilities Total lease liabilities Undiscounted lease payments to be received 1 year 2 years 3 years 4 years 5 years >5 years Consolidated 2018 $’000 2017 $’000 3,681 3,605 13,588 17,269 18,375 21,980 451 469 488 510 204 - 433 451 469 488 510 204 2,122 2,555 Refer to Note 7 for interest expense on the lease liabilities and the consolidated statement of cash flows for the total cash outflow for the leases. Recognition and measurement Leased assets Leased assets are capitalised at the commencement date of the lease and comprise of the initial lease liability amount, initial direct costs incurred when entering into the lease less any lease incentives received. On initial adoption of AASB 16 the Group has adjusted the right-of-use assets at the date of initial application by the amount of any provision for onerous leases recognised immediately before the date of initial application. Following initial application, an impairment review is undertaken for any right of use lease asset that shows indicators of impairment and an impairment loss is recognised against any right of use lease assets that is impaired. R E W O P M R E 6 8 18. LEASE ASSETS AND LIABILITIES (CONTINUED) Leased liabilities The lease liability is measured at the present value of the fixed and variable lease payments net of cash lease incentives that are not paid at the balance date. Lease payments are apportioned between the finance charges and reduction of the lease liability using the incremental borrowing rate implicit in the lease to achieve a constant rate of interest on the remaining balance of the liability. Lease payments for buildings exclude service fees for cleaning and other costs. Lease modifications are accounted for as a new lease with an effective date of the modification. Key judgments and estimates Amortisation Amortisation of leased assets is calculated using the straight-line method to allocate their cost, net of their residual values, over their estimated useful lives being the lesser of the remaining lease term and the life of the asset. 19. TRADE AND OTHER PAYABLES Current Trade creditors and accruals Other creditors Consolidated 2018 $’000 2017 $’000 268,525 155,114 423,639 344,335 119,979 464,314 Recognition and measurement These amounts represent liabilities for goods and services provided to the Group prior to the end of the financial period and which are unpaid. The amounts are unsecured and are usually paid within 60 days of recognition. Key judgments and estimates Accrued electricity network costs Accrued electricity network costs payable requires estimates of average daily usage where no meter data is available. This usage estimate is combined with a customer specific network tariff to estimate accrued network costs. t r o p e R l a u n n A 8 1 0 2 7 8 Notes to the Consolidated Financial Statements SECTION 2: OPERATING ASSETS AND LIABILITIES 20. PROVISIONS Current Employee benefits - annual leave Customer acquisition cost provision Non-current Employee benefits - long service leave Customer acquisition cost provision Movements in provisions Carrying amount at start of the year Onerous contract provision derecognised on adoption of AASB16 Leases Additional provision recognised and charged to profit and loss Amounts used during the year Current period trailing commission sales and additions provision recognised Current period commission sales paid Classified as held for sale Exchange differences Note Consolidated 2018 $’000 2017 $’000 (i) (ii) 31 2,093 4,503 6,596 1,880 2,342 4,222 37,417 - 2,669 (2,087) 36,401 (26,096) (39,181) 1,695 10,818 2,167 12,644 14,811 1,573 21,033 22,606 27,426 (1,850) 2,165 (2,598) 22,548 (9,019) (242) (1,013) 37,417 (i) The entire amount of the annual leave provision is presented as current since the Group does not have an unconditional right to defer settlement for any of these obligations. In addition, based on past experience, the Group expects all employees to take the full amount of accrued leave or require payment within the next 12 months. (ii) Corresponding amount capitalised as an intangible asset. Recognition and measurement Commission payments Customer contracts that are acquired through commission agreements have a corresponding provision liability recognised. The provision liability is measured against forecast payments required and is discounted at a risk free rate. Employee benefits Liabilities arising in respect of wages and salaries, annual leave and any other employee entitlements expected to be settled within 12 months of balance date are measured at the amounts expected to be paid when the liabilities are settled. Long service leave liabilities are measured at the present value of the estimated future cash outflow to be made in respect of services provided by employees up to balance date. Consideration is given to expected future wage and salary levels, projected employee movements and periods of service. Expected future payments are discounted using the G100 discount rate for corporate bonds at balance date that matches, as closely as possible, the estimated future cash flows. Liabilities for employee benefits in the form of bonus plans are recognised in liabilities when it is probable that the liability will be settled and there are formal terms in place to determine the amount of the benefit. Liabilities for bonus plans are expected to be settled within 12 months and are measured at the amounts expected to be paid when they are settled. Key judgments and estimates Employee benefits Provisions for employee benefits include assumptions around expected future wage and salary levels and expected periods of service for the purposes of assessing the long service leave liability. Commission payments Provisions for commission payments include assumptions around forecast electricity usage for currently contracted customers acquired through a brokerage arrangement. R E W O P M R E 8 8 21. DEFERRED TAX ASSETS AND LIABILITIES Recognised deferred tax assets and deferred tax liabilities Movement in temporary differences - consolidated Note Opening balance $’000 Recognised in income statement $’000 Currency translation differences $’000 Recognised in equity $’000 Closing balance $’000 2018 Carried forward income tax losses Net derivative financial liabilities Employee provisions Lease liabilities Other items Deferred tax assets Set-off deferred tax liabilities Write-down of deferred tax assets (i) Net deferred tax assets Net derivative financial assets Property, plant and equipment and intangibles Lease assets Goodwill Associates Other items Deferred tax liabilities Set-off deferred tax assets Net deferred tax liabilities Net deferred tax assets for discontinued operations 31/(ii) Net deferred tax liabilities for continuing operations 2017 Carried forward income tax losses Employee provisions Lease liabilities Other items Deferred tax assets Set-off deferred tax liabilities Net deferred tax assets Net derivative financial assets Property, plant and equipment and intangibles Lease assets Goodwill Associates Other items Deferred tax liabilities Set-off deferred tax assets Net deferred tax liabilities 5,817 - 4,352 6,662 7,785 24,616 (109,576) (68,976) (4,375) (1,650) (72) (4,497) (189,146) 11,821 1,361 2,022 4,752 19,956 (49,176) (61,001) - (882) - (2,778) 4,692 14,389 284 (1,249) 622 18,738 13,587 (8,553) 1,023 320 (107) (727) 5,543 (5,870) 2,992 1 3,046 169 (10,424) (7,951) (50) (799) (72) (1,719) 1,117 - 58 17 37 1,229 87 34 (13) (121) - (3) (16) (134) 3 (13) (145) (16) (24) (2) 31 - - - - - - - - 95,902 - - - - 28 11,626 14,389 4,694 5,430 8,444 44,583 (30,594) (10,279) 3,710 - (77,495) (3,365) (1,451) (179) (5,199) 95,930 (87,689) 30,594 (57,095) 3,710 (57,095) 5,817 4,352 6,662 7,785 24,616 (10,766) 13,850 - - 4,636 - 4,636 (49,960) (109,576) - (68,976) (4,323) - - - (4,375) (1,650) (72) (4,497) (113,837) (21,015) (11) (54,283) (189,146) 10,766 (178,380) (i) Estimated non-recoverability of US deferred tax assets. (ii) The deferred tax asset remaining for the US discontinued operations relates to the amount expected to be recoverable on sale. Recognition and measurement t r o p e R l a u n n A 8 1 0 2 9 8 Notes to the Consolidated Financial Statements SECTION 2: OPERATING ASSETS AND LIABILITIES 21. DEFERRED TAX ASSETS AND LIABILITIES (CONTINUED) Recognition and measurement Deferred tax assets are recognised for deductible temporary differences and unused tax losses only if it is probable that future taxable amounts will be available to utilise those temporary differences and losses. Deferred tax liabilities and assets are not recognised for temporary differences between the carrying amount and tax bases of investments in controlled entities where the entity is able to control the timing of the reversal of the temporary differences and it is probable that the differences will not reverse in the foreseeable future. Deferred tax assets and liabilities are offset when there is a legally enforceable right to offset current tax assets and liabilities and when the deferred tax balances relate to the same taxation authority. Current tax assets and tax liabilities are offset where the entity has a legally enforceable right to offset and intends either to settle on a net basis, or to realise the asset and settle the liability simultaneously. Deferred tax assets and liabilities have not been recognised for the following items: Tax losses not recognised Unused capital tax losses for which no deferred tax asset has been recognised Unused tax losses for which no deferred tax asset has been recognised – continuing operations Unused tax losses for which no deferred tax asset has been recognised – discontinued operation Potential Australian tax benefit at 30% Potential US tax benefit at 21% Note (i) (ii) (iii) Consolidated 2018 $’000 15,127 698 37,697 4,748 7,916 2017 $’000 15,127 - - 4,538 - (i) The unused capital losses were incurred from the disposal of capital investments that are not likely to be recouped in the foreseeable future. (ii) The unused tax losses were incurred by a joint venture the Group invests in. The losses are not likely to generate taxable income in the foreseeable future. (iii) The unused tax losses were incurred by the US business Source Power & Gas that is not likely to generate taxable income in the foreseeable future. Unrecognised temporary differences Temporary difference relating to investments in subsidiaries for which deferred tax balances have not been recognised: Foreign currency translation Net US deferred tax balances Unrecognised deferred tax liabilities relating to the above temporary differences Unrecognised deferred tax assets relating to the above temporary differences Consolidated 2018 $’000 (2,671) 11,251 (561) 2,363 2017 $’000 (1,361) - (476) - Temporary differences of a net $1.8m asset (2017: $0.5m liability) have arisen as a result of unrealised mark to market valuations of derivatives, employee provisions, timing differences between tax and accounting depreciation, the translation of the financial statements of the Group’s subsidiary in the US and other various items. However, a deferred tax asset has not been recognised as taxable profit against which the asset can be utilised is not expected to be available. R E W O P M R E 0 9 21. DEFERRED TAX ASSETS AND LIABILITIES (CONTINUED) Tax consolidation The Company and its wholly-owned Australian controlled entities, have implemented the tax consolidation legislation. The entities in the tax consolidated group have entered into tax sharing agreements which, in the opinion of the directors, limits the joint and several liability of the wholly-owned entities in the case of a default by the head entity being ERM Power Limited. The entities in the tax consolidated group have also entered into tax funding agreements under which the wholly-owned entities fully compensate the head entity for any current tax payable assumed and are compensated by the head entity for any current tax receivable and deferred tax assets relating to unused tax losses or unused tax credits that are transferred to the head entity under the tax consolidation legislation. The funding amounts are determined by reference to the amounts recognised in the wholly-owned entities’ financial statements. The amounts receivable/payable under the tax funding agreement are due upon receipt of the funding advice from the head entity, which is issued as soon as practicable after the end of each financial year. The head entity may also require payment of interim funding amounts to assist with its obligations to pay tax instalments. The funding amounts are recognised as current intercompany receivables or payables. Key judgments and estimates Deferred tax assets The Group has recognised deferred tax assets relating to carried forward tax losses to the extent there are sufficient taxable temporary differences (deferred tax liabilities) relating to the same taxation authority against which the unused tax losses can be utilised. However, utilisation of the tax losses also depends on the ability of the entity to satisfy certain tests at the time the losses are recouped. t r o p e R l a u n n A 8 1 0 2 1 9 Notes to the Consolidated Financial Statements SECTION 3: CAPITAL AND FINANCIAL RISK MANAGEMENT 22. FINANCIAL RISK MANAGEMENT Financial risk management objectives The Group’s activities are exposed to a variety of financial risks, including: (a) Market risk (commodity price and interest rate), (b) (c) Credit risk (refer Note 10), and Liquidity risk. The Group’s overall risk management strategy focuses on the unpredictability of markets and seeks to minimise potential adverse effects on the financial performance of the Group. The Group uses a variety of derivative financial instruments such as electricity derivatives and interest rate swaps to hedge against certain risk exposures. Further details on these instruments are set out in notes 13 and 14. The Group uses different methods to measure the different types of risk to which it is exposed. These methods include sensitivity analysis in the case of interest rate, foreign exchange and other price risks, and ageing analysis for credit risk. Market risk Electricity pool price risk The Group is exposed to fluctuations in wholesale market electricity prices as a result of electricity generation and sales. Group policies prescribe active management of exposures arising from forecast electricity sales within prescribed limits. In doing so, various hedging contracts have been entered into with individual market participants. Any unhedged position has the potential for variation in net profit from fluctuations in electricity pool prices. Subsidiaries in the Group’s electricity sales segment routinely enter into forward sales contracts for the provision of electricity. The Group is exposed to a market risk of price fluctuations between the fixed price of these contracts and the relevant spot price of the electricity pool at the time of usage. The majority of this exposure to fluctuations in wholesale market electricity prices is managed through the use of various types of hedging contracts. The hedge portfolio consists predominantly of swaps, caps, futures and options. Electricity derivatives are either entered into in separate agreements or arise as embedded derivatives. Whilst the Group recognises the fair value of electricity derivative contracts for accounting purposes, the Group is not permitted to similarly recognise the fair value of the sales contracts that form the other side of the economic hedging relationship. The following tables summarise the impact of a 10% change in the relevant forward prices for wholesale market electricity prices for the Group at the balance date, while all other variables were held constant. Electricity sales sensitivity The impact disclosed below summarises the sensitivity on the unrealised mark to market of electricity derivatives contracts only and does not include any corresponding movement in the value of customer contracts, which would vary in the opposite direction to the underlying hedge. As electricity forward prices increase above the contracted price of a derivative contract (buy side contract) the derivative contract becomes more valuable as it allows the Group to effectively purchase electricity at a cost lower than the prevailing forward market price. Equally, the value of the corresponding customer contract (sell side contract) decreases as the Group has contracted to sell electricity to a customer at a price lower than the prevailing forward market price. Only the mark to market on the buy side contract has been recognised for accounting purposes regardless of whether there is an effective hedge in place. 2018 Net profit / (loss) – unrealised mark to market of electricity derivative contracts Other Components of Equity increase / (decrease) Increase by 10% $’000 Decrease by 10% $’000 185,428 83,404 (157,180) (215,847) 2017 Net profit / (loss) – unrealised mark to market of electricity derivative contracts Other Components of Equity increase / (decrease) 96,862 198,957 (5,610) (167,269) Sensitivity of 10% has been selected as this is considered reasonably possible based on industry standard benchmarks and historical volatilities. R E W O P M R E 2 9 22. FINANCIAL RISK MANAGEMENT (CONTINUED) Electricity generation sensitivity The impact disclosed below summarises the sensitivity on the profit of generating assets held by the Group resulting from a change in spot prices. 2018 Net profit / (loss) Other Components of Equity increase / (decrease) 2017 Net profit / (loss) Other Components of Equity increase / (decrease) Increase by 10% $’000 Decrease by 10% $’000 5,695 - 3,687 - (5,695) - (3,687) - Sensitivity of 10% has been selected as this is considered reasonably possible based on industry standard benchmarks and historical volatilities. Interest rate risk The Group is exposed to interest rate risk on the funds it borrows at floating interest rates and on cash deposits. The risk is managed by entering into interest rate swap contracts for project term debt. The sensitivity analysis to net profit (being profit before tax) and equity has been determined based on the exposure to interest rates at the balance date and assumes that there are concurrent movements in interest rates and parallel shifts in the yield curves. A sensitivity of 50 basis points has been selected as this is considered reasonable given the current level of short term and long term interest rates. At balance date, if interest rates had been 50 basis points higher / lower and all other variables were held constant, the impact on the Group would be: 2018 Net profit / (loss) Other equity increase / (decrease) 2017 Net profit / (loss) Other equity increase / (decrease) Increase by 50bps $’000 Decrease by 50bps $’000 434 2,141 (434) (2,141) 663 2,504 (663) (2,504) The impact on net profit is largely due to the Group’s exposure to interest rates on its non-hedged variable rate borrowings and cash assets. Foreign exchange risk The Group operates a US electricity retail business and is exposed to foreign currency translation risk in respect of the investment. There is no debt in respect of this investment and there are no cross currency transactions that expose the Group to further foreign exchange risk. Liquidity risk Liquidity risk is the risk that the Group will not be able to meet its financial obligations as they fall due. Prudent liquidity risk management implies maintaining sufficient cash and marketable securities, the availability of funding through an adequate amount of committed credit facilities and the ability to close out market positions. The Group manages liquidity risk by continuously monitoring forecast and actual cash flows and matching the maturity profiles of financial assets and liabilities. Surplus funds are generally only invested in instruments that are tradeable in highly liquid markets. Information regarding undrawn finance facilities available as at 30 June 2018 is contained in Note 25. Maturities of financial liabilities The table below analyses the Group’s financial liabilities, including net and gross settled derivative financial instruments, into relevant maturity groupings based on the remaining period at balance date to the contractual maturity date. The amounts disclosed in the table are the contractual undiscounted cash flows. For interest rate swaps the cash flows have been estimated using forward interest rates applicable at balance date. For electricity derivatives the cash flows have been estimated using forward electricity prices at balance date. t r o p e R l a u n n A 8 1 0 2 3 9 Notes to the Consolidated Financial Statements SECTION 3: CAPITAL AND FINANCIAL RISK MANAGEMENT 22. FINANCIAL RISK MANAGEMENT (CONTINUED) Financial liabilities Consolidated 2018 Trade payables and accrued expenses Other payables Leased liabilities Interest bearing liabilities Interest bearing liabilities – limited recourse(i) Derivatives 2017 Trade payables and accrued expenses Other payables Leased liabilities Interest bearing liabilities – limited recourse(i) Derivatives ≤1 year $’000 1 to 5 years $’000 >5 years $’000 Discount $’000 Total $’000 268,525 155,114 4,276 150,831 8,904 34,511 - - 14,509 - 96,722 74,762 622,161 185,993 344,335 119,979 4,383 8,264 40,758 517,719 - - 17,961 30,587 53,592 - - - - 87,814 4,149 91,963 - - 2,010 159,603 6,992 - - (1,516) - (7,969) - 268,525 155,114 17,269 150,831 185,471 113,422 (9,485) 890,632 - - (2,374) (9,537) - 344,335 119,979 21,980 188,917 101,342 102,140 168,605 (11,911) 776,553 (i) Recourse limited to assets of the Neerabup Partnership. Refer note 29 for further details. Capital risk management The Group manages its capital so that it will be able to continue as a going concern while maximising the return to stakeholders through an appropriate mix of debt and equity. This approach is consistent with prior years. The capital structure of the Group as at balance date consists of total corporate facilities, as listed in note 25, total limited recourse facilities as listed in note 25 and equity, comprising issued capital, reserves and retained earnings as listed in notes 26 and 27. In order to maintain or adjust the capital structure, the Group may adjust the amount of dividends paid to shareholders, return capital to shareholders, issue new shares or sell assets to reduce debt. The Group is required to provide prudential credit support to various parties which it does through the provision of bank guarantees or cash collateral. It also has a working capital facility in place which is settled each month. A large percentage of the Group debt is in the form of limited recourse project finance provided directly to power stations in which the Group has an interest. During the financial year ended 30 June 2018 the entity complied with all applicable debt covenants. The quantitative analysis of the Group’s gearing structure is illustrated below. To consider the risk of the Company’s capital structure it is appropriate to segregate the power stations from the rest of the Group. The table below illustrates the gearing and interest cover for the Group. When the Neerabup assets and associated limited recourse debt are excluded the Group has no net debt. Gearing percentage(i) Gearing percentage(i) excluding Neerabup EBITDAF Interest cover ratio for continuing operations Consolidated 2018 $’000 28.2% 0% 3.57 2017 $’000 0% 0% 3.19 (i) Gearing percentage is calculated as net debt divided by total capital. Net debt is calculated as total interest-bearing borrowings less cash and cash equivalents. Total capital is calculated as ‘equity’ as shown in the statement of financial position plus net debt less reserves attributable to fair value adjustments. R E W O P M R E 4 9 23. FAIR VALUE MEASUREMENT Fair value of financial assets and liabilities The fair value of financial assets and financial liabilities must be estimated for recognition, measurement and disclosure purposes. The carrying amounts and estimated fair values of all the Group’s financial instruments recognised in the financial statements are materially the same, with the exception of the following: Financial assets Electricity and gas derivative financial instruments Consolidated 2018 $’000 Carrying value 99,095 99,095 2018 $’000 Fair value 123,126 123,126 The carrying value of derivative financial assets recognised excludes a day one gain on certain electricity derivatives. In accordance with the Groups accounting policy a day one gain has not been recognised with the day one value of certain instruments entered into initially valued at the transaction price, which is the best indicator of fair value. Any gain subsequently realised is progressively recognised as the instruments are settled. The measurement of the instruments at 30 June 2018 excludes the remaining balance of the deferred day one gain of $24.1m. At inception the day one gain was $31.9m. The movement in the day one gain balance relates to settlement of derivatives through profit and loss during the year. Key judgments and estimates The fair value of financial assets and financial liabilities must be estimated for recognition and measurement and for disclosure purposes. The financial assets and liabilities held by the Group and the fair value approach for each is outlined below: Financial asset and liability Fair value approach Cash and cash equivalents The carrying amount is fair value due to the asset’s liquid nature. Derivative financial instruments The fair value of derivative instruments included in hedging assets and liabilities is calculated using quoted prices. The fair value of financial instruments that are not traded in an active market (for example, over-the-counter derivatives) is determined using valuation techniques. The Group uses a variety of methods, such as discounted cash flows, and makes assumptions that are based on market conditions existing at each balance date. These amounts reflect the estimated amount which the Group would be required to pay or receive to terminate (or replace) the contracts at their current market rates at balance date. Where the derivative instrument life extends beyond the period of available market data valuation techniques and assumptions are used in the fair value estimate. Other financial assets Due to their short-term nature, the carrying amounts of loans, receivables, and cash and cash equivalents approximate their fair value. Other financial liabilities at amortised cost The Group holds various trade payables and borrowings at period end. Due to the short-term nature of the trade payables the carrying value of these are assumed to approximate their fair value. The fair value of borrowings is not materially different then the carrying amounts as the interest rates are close to current market rates or are short-term in nature. t r o p e R l a u n n A 8 1 0 2 5 9 Notes to the Consolidated Financial Statements SECTION 3: CAPITAL AND FINANCIAL RISK MANAGEMENT 23. FAIR VALUE MEASUREMENT (CONTINUED) The following tables present the Group’s assets and liabilities measured and recognised at fair value at 30 June 2018 and 30 June 2017. As at 30 June 2018 Assets Electricity and commodity derivatives Financial assets at fair value through other comprehensive income Total assets Liabilities Electricity and commodity derivatives Interest rates swaps Total liabilities As at 30 June 2017 Assets Electricity and commodity derivatives Embedded derivative contract Financial assets at fair value through other comprehensive income Total assets Liabilities Electricity and commodity derivatives Interest rates swaps Total liabilities Level 1 Level 1 $’000 Level 2 $’000 Level 3 $’000 Total $’000 5,233 93,862 9 - 5,242 93,862 1,790 - 1,790 82,151 29,481 111,632 - - - - - - 99,095 9 99,104 83,941 29,481 113,422 Level 1 $’000 Level 2 $’000 Level 3 $’000 Total $’000 8,871 397,705 - 15 30 - 8,886 397,735 7,983 - 7,983 59,547 33,812 93,359 - - - - - - - 406,576 30 15 406,621 67,530 33,812 101,342 The fair value of financial instruments traded in active markets is based on quoted market prices at the end of the reporting period. The quoted market price used for financial assets held by the Group is the current bid price. Level 2 The fair values of financial instruments that are not traded in an active market are determined using valuation techniques. The Group uses a variety of methods and makes assumptions that are based on market conditions existing at the end of each reporting period. Quoted market prices or dealer quotes for similar instruments are used to estimate fair value for long-term debt for disclosure purposes. Other techniques, such as estimated discounted cash flows, are used to determine fair value for the remaining financial instruments. The fair value of interest rate swaps is calculated as the present value of the estimated future cash flows. Level 3 A valuation technique for these instruments is based on significant unobservable inputs. The Group’s policy is to recognise transfers into and transfers out of fair value hierarchy levels as at the end of the reporting period. For the years ending 30 June 2018 and 30 June 2017 there were no transfers between the fair value hierarchy levels. Offsetting of financial assets and financial liabilities Financial assets and liabilities are offset and the net amount reported in the balance sheet where the Group currently has a legally enforceable right to offset the recognised amounts, and there is an intention to settle on a net basis or realise the asset and settle the liability simultaneously. The Group has also entered into arrangements that do not meet the criteria for offsetting but still allow for the related amounts to be set off in certain circumstances, such as bankruptcy or the termination of a contract. The following table presents the recognised financial instruments that are offset, or subject to enforceable master netting arrangements and other similar agreements but not offset, as at 30 June 2018 and 30 June 2017. The column ‘net exposure’ shows the impact on the Group’s balance sheet if all set-off rights were exercised. R E W O P M R E 6 9 23. FAIR VALUE MEASUREMENT (CONTINUED) The below table provides a reconciliation of the Group’s gross derivative financial assets and liabilities offset to those presented on the consolidated statement of financial position as at 30 June 2018 and as at 30 June 2017. As at 30 June 2018 $’000 Financial assets Electricity and commodity derivatives contracts Total Financial liabilities Electricity and commodity derivatives contracts Interest rate swaps Total As at 30 June 2017 $’000 Financial assets Electricity and commodity derivatives contracts Gross carrying amount (before offsetting) Gross amounts offset Cash collateral and futures margin deposits paid / (received) Net amount presented Related amounts not offset Financial instruments(i) Cash collateral Net exposure 245,467 (172,457) 26,085 99,095 (12,225) 245,467 (172,457) 26,085 99,095 (12,225) - - 86,870 86,870 256,398 (172,457) 29,481 - 285,879 (172,457) - - - 83,941 (12,225) 9,997 81,713 29,481 113,422 - - (12,225) 9,997 29,481 111,194 Gross carrying amount (before offsetting) Gross amounts offset Cash collateral and futures margin deposits paid / (received) Net amount presented Related amounts not offset Financial instruments(i) Cash collateral Net exposure 547,777 (78,192) (63,009) 406,576 (3,925) (46,462) 356,189 Foreign exchange derivatives contract 30 - - 30 - - 30 Total 547,807 (78,192) (63,009) 406,606 (3,925) (46,462) 356,219 Financial liabilities Electricity and commodity derivatives contracts Interest rate swaps Total 145,948 (78,192) (226) 67,530 (3,925) 1,340 64,945 33,812 - - 33,812 - - 179,760 (78,192) (226) 101,342 (3,925) 1,340 33,812 98,757 (i) Financial instruments that do not meet the criteria for offsetting but may be offset in certain circumstances. 24. CASH AND CASH EQUIVALENTS Current Restricted cash Non-restricted cash at bank and cash on hand Total cash and cash equivalents The cash and cash equivalents are bearing interest at rates between nil and 2.75%. Restricted cash Term deposits Other restricted cash deposits Consolidated 2018 $’000 2017 $’000 160,038 67,598 227,636 34,120 125,918 160,038 118,465 126,151 244,616 33,547 84,918 118,465 t r o p e R l a u n n A 8 1 0 2 7 9 Notes to the Consolidated Financial Statements SECTION 3: CAPITAL AND FINANCIAL RISK MANAGEMENT 24. CASH AND CASH EQUIVALENTS (CONTINUED) Restricted cash Cash that is reserved and its use specifically restricted for maintenance and/or debt servicing under the Group’s borrowing agreements is defined as restricted cash. Cash that is on deposit with counterparties as security deposits and cash that is on deposit with financial institutions as security for bank guarantees issued to various counterparties as credit support, is defined as restricted cash, with a corresponding disclosure in contingent liabilities in Note 34. Cash collateral held in margin accounts to facilitate wholesale price hedging on the ASX Energy Exchange is classified as restricted cash unless it is eligible for offset against the corresponding derivative liability. As at 30 June 2018 $22.3m cash collateral held in initial margin accounts has been offset against the corresponding asset or liability (2017: $96.4m). The restricted cash deposits, held on term deposit, are bearing interest at rates between 1.75% and 2.75%. Recognition and measurement Cash and cash equivalents comprise cash on hand, deposits held at call with financial institutions, and other short-term highly liquid investments with original maturities of three months or less that are readily convertible into known amounts of cash and which are subject to an insignificant risk of changes in value, net of any bank overdrafts. These assets are stated at nominal values. Cash that is reserved and its use specifically restricted for maintenance and / or debt servicing under the Group’s borrowing agreements is defined as restricted cash. Cash that is on deposit with counterparties as security deposits and cash that is on deposit with financial institutions as security for bank guarantees issued to various counterparties as credit support, is defined as restricted cash, with a corresponding disclosure in contingent liabilities in Note 34. Cash collateral held in margin accounts to facilitate wholesale price hedging on the ASX Energy Exchange is classified as restricted cash unless it is eligible for offset against the corresponding derivative liability. 25. BORROWINGS Current Secured Bank loan - Receivables financing facility Secured - limited recourse Bank loan - Neerabup working capital facility Bank loan - Neerabup term facility Total current borrowings Non-current Secured - limited recourse Bank loan - Neerabup term facility Convertible notes Total non-current borrowings Total borrowings Note Consolidated 2018 $’000 2017 $’000 (i) (ii) (iii) (iii) (iv) 150,831 150,831 3,000 5,904 8,904 159,735 124,537 52,030 176,567 176,567 - - 3,000 5,264 8,264 8,264 130,190 50,463 180,653 180,653 336,302 188,917 Information on credit risk, fair value and interest rate risk exposure of the Group is provided at note 22. (i) Amounts drawn down on receivables financing facility secured against billed and unbilled electricity sales customer revenue receivables. The facility is available until July 2020. (ii) Amounts drawn down on a limited recourse bank working capital facility by Neerabup Partnership. This debt has recourse to the assets of Neerabup Partnership only. (iii) Amounts drawn down on a limited recourse term debt facility in respect of the Neerabup Partnership. This debt has recourse to the assets of Neerabup Partnership only. (iv) Convertible notes are redeemable by the issuer from 30 September 2010 until maturity in February 2023. Notes have a coupon rate that is variable based on BBSY plus 4%. The notes are accounted for using the effective interest method at 7.62% (2017: 7.78%). The notes can only be converted to shares in the issuing subsidiary upon failure to redeem them at maturity or other named event of default. The notes have recourse to the Group’s 50% interest in the Neerabup partnership only. R E W O P M R E 8 9 25. BORROWINGS (CONTINUED) Financing facilities available The Group’s financing facilities predominantly relate to limited recourse power station development activities. Funding is drawn down progressively according to project time lines. At balance date, the following financing facilities had been negotiated and were available: Total facilities - bank loans Facilities used at balance date - bank loans Facilities unused at balance date - bank loans Consolidated 2018 $’000 413,123 2017 $’000 391,463 (324,426) (179,020) 88,697 212,443 Recognition and measurement Borrowings are initially recognised at fair value, net of transaction costs incurred. Borrowings are subsequently measured at amortised cost using the effective interest method, with interest expense recognized on an effective yield basis. The effective interest method is a method of calculating the amortised cost of a financial liability and of allocating interest expense over the relevant period. The effective interest rate is the rate that discounts estimated future cash payments through the expected life of the financial liability, or, where appropriate, a shorter period. Any difference between the proceeds (net of transaction costs) and the redemption amount is recognised in profit or loss over the period of the borrowings using the effective interest method. Fees paid on the establishment of loan facilities are recognised as transaction costs of the loan to the extent that it is probable that some or all of the facility will be drawn down. In this case, the fee is deferred until the draw down occurs. To the extent there is no evidence that it is probable that some or all of the facility will be drawn down, the fee is capitalised as a prepayment for liquidity services and amortised over the period of the facility to which it relates. Preference shares, which are mandatorily redeemable on a specific date, are classified as liabilities. The dividends on these preference shares are recognised in profit or loss as finance costs. Borrowings are removed from the statement of financial position when the obligation specified in the contract is discharged, cancelled or expired. The difference between the carrying amount of a financial liability that has been extinguished or transferred to another party and the consideration paid, including any non-cash assets transferred or liabilities assumed, is recognised in profit or loss as other income or finance costs. Borrowings are classified as current liabilities unless the Group has an unconditional right to defer settlement of the liability for at least 12 months after the reporting period. t r o p e R l a u n n A 8 1 0 2 9 9 Notes to the Consolidated Financial Statements SECTION 3: CAPITAL AND FINANCIAL RISK MANAGEMENT 26. CONTRIBUTED EQUITY Issued ordinary shares – fully paid Treasury shares Movement in ordinary share capital At the beginning of the period Note Consolidated Consolidated 2018 Number of shares 2017 Number of shares 255,421,056 252,708,202 (7,531,156) (7,648,455) 247,889,900 245,059,747 2018 $’000 2017 $’000 350,745 (10,314) 340,431 346,621 (11,609) 335,012 252,708,202 245,836,004 346,621 339,669 Issue of new shares – employee incentive scheme 33 3,948,853 5,588,171 Issue of shares – dividend reinvestment plan Shares bought back on-market and cancelled, including transaction costs (net of tax) Transfer from share buy-back reserve Transfer from share based payment reserve Transfer to treasury shares At the end of the period 503,561 1,284,027 (1,739,560) - - - - - - - 6,841 673 (2,880) 408 3,052 (3,970) 5,606 1,301 - - 304 (259) 255,421,056 252,708,202 350,745 346,621 Terms and conditions of contributed equity Ordinary shares During the year ended 30 June 2018, there were no capital raisings undertaken. Ordinary shares have the right to receive dividends as declared and, in the event of winding up the Company, to participate in the proceeds from the sale of all surplus assets in proportion to the number of shares held. Ordinary shares entitle their holder to one vote, either in person or by proxy, at a meeting of the Company. Ordinary shares have no par value and the Company does not have a limited amount of authorised capital. Treasury shares Treasury shares are shares that are held in trust for the purpose of issuing shares under employee share incentive schemes. For details of shares and options issued under employee share schemes see note 33. Share buy-back During the year ended 30 June 2018, the Company purchased and cancelled 1,739,560 ordinary shares on-market. The shares were acquired at an average price of $1.61. The total cost of $2.9m, including $0.1m of after tax transaction costs, was deducted from contributed equity. As the shares were bought back at an average price in excess of the share capital issued, $0.4m was transferred to the share buy-back reserve. The total reduction in paid up capital was $2.5m. Recognition and measurement Ordinary shares are classified as equity. Incremental costs directly attributable to the issue of ordinary shares and share options are recognised as a deduction from equity, net of any tax effects. R E W O P M R E 0 0 1 27. RESERVES Consolidated Cash flow hedge reserve $’000 Fair value reserve $’000 Share based payment reserve $’000 Share buy-back reserve $’000 Transactions with non- controlling interests $’000 Foreign currency translation reserve $’000 Total $’000 2018 Balance at the beginning of the year Revaluation - net Revaluation - deferred tax Share based payments vested Share based payments expense Transfer to contributed equity Currency translation differences 228,912 (319,674) 95,902 - - - - (1,042) 6,050 (6) - - - - - - - (3,052) 2,774 - - - - - - - (408) - Balance at the end of the year 5,140 (1,048) 5,772 (408) (14,404) (14,404) 1,361 220,877 - - - - - - - - - - - 1,310 2,671 Consolidated 2017 Balance at the beginning of the year Revaluation - net Revaluation - deferred tax Share based payments vested Share based payments expense Currency translation differences Reclassification to profit or loss on disposal of discontinued operations Cash flow hedge reserve $’000 Fair value reserve $’000 Share based payment reserve $’000 Share buy-back reserve $’000 Transactions with non- controlling interests $’000 Foreign currency translation reserve $’000 112,338 166,534 (49,960) - - - - (900) (142) - - - - - 3,676 - - (1,153) 3,527 - - (14,404) 2,703 - - - - - - - - - - (1,137) (205) - - - - - - - - Balance at the end of the year 228,912 (1,042) 6,050 (14,404) 1,361 220,877 (319,680) 95,902 (3,052) 2,774 (408) 1,310 (2,277) Total $’000 103,413 166,392 (49,960) (1,153) 3,527 (1,137) (205) Cash flow hedge reserve The cash flow hedge reserve comprises the effective portion of the cumulative net change in the fair value of cash flow hedging instruments related to hedged transactions that have not yet occurred. Fair value reserve Changes in the fair value and exchange differences arising on translation of investments, such as equities classified as fair value through other comprehensive income, are recognised in other comprehensive income and accumulated in a separate reserve within equity. Share based payment reserve The share based payments reserve is used to recognise: • • the grant date fair value of options issued to employees but not exercised; the grant date fair value of shares issued to employees; and the issue of shares held by the EST and LTIOT employee share trusts to employees. • Share buy-back reserve The share buy-back reserve is used to record the difference in the average share price for the shares bought back compared to the share capital issued prior to the buy-back. Transactions with non-controlling interests This reserve is used to record the differences described in note 38 which may arise as a result of transactions with non-controlling interests that do not result in a loss of control. Foreign currency translation Exchange differences arising on translation of the foreign controlled entity are recognised in other comprehensive income as described in note 38(a) and accumulated in a separate reserve within equity. The cumulative amount is reclassified to profit or loss when the net investment is disposed of. t r o p e R l a u n n A 8 1 0 2 1 0 1 Notes to the Consolidated Financial Statements SECTION 4: GROUP STRUCTURE 28. PARENT ENTITY FINANCIAL INFORMATION The individual financial statements for the parent entity show the following aggregate amounts Statement of financial position Current assets Total assets Current liabilities Total liabilities Net assets Shareholders’ equity Contributed equity Treasury shares Fair value reserve Share based payment reserve Share buy-back reserve Retained earnings Total equity (Loss) / profit for the year Other comprehensive loss Total comprehensive (loss) / income 2018 $’000 245,901 398,750 18,690 34,102 364,648 350,745 (10,314) (1,048) 5,772 (408) 19,901 364,648 (49,753) (6) (49,759) 2017 $’000 319,351 474,843 30,093 47,228 427,615 346,621 (11,609) (1,042) 6,050 - 87,595 427,615 80,674 (142) 80,532 Guarantees entered into by the parent entity The parent entity has issued non-cash backed guarantees to certain third parties to support the operations of the Australia and US electricity sales businesses. Contingent liabilities of the parent entity At 30 June 2018, the parent entity has drawn on $180m of non-cash backed financial guarantees under the Liberty International Underwriters Singapore Surety guarantee facility. The guarantee is drawn to support Australian energy market operational obligations as detailed in note 34(b). Contractual commitments for acquisition of property, plant and equipment There are no contractual commitments for the acquisition of property, plant and equipment at 30 June 2018. Parent entity financial information The financial information for the parent entity, ERM Power Limited has been prepared on the same basis as the consolidated financial statements, except as set out below: (a) Investments in subsidiaries, associates and joint arrangements Investments in subsidiaries, associates and joint venture entities are accounted for at cost in the financial statements of the Company. Dividends received from associates are recognised in the parent entity’s profit or loss, rather than being deducted from the carrying amount of these investments. (b) Financial Guarantees Where the parent entity provides financial guarantees in relation to loans and payables of subsidiaries for no compensation, the fair values of these guarantees are accounted for as contributions and recognised as part of the cost of the investments. R E W O P M R E 2 0 1 28. PARENT ENTITY FINANCIAL INFORMATION (CONTINUED) (c) Share-based payments The grant by the Company of options over its equity instruments to the employees of subsidiary undertakings in the Group is treated as a capital contribution to that subsidiary undertaking. The fair value of employee services received, measured by reference to the grant date fair value, is recognised over the vesting period as an increase to investment in subsidiary undertakings, with a corresponding credit to equity. (d) Tax consolidation legislation The Company and its wholly-owned Australian controlled entities have implemented the tax consolidation legislation. The head entity ERM Power Limited, and the controlled entities in the tax consolidated group, account for their own current and deferred tax amounts. These tax amounts are measured as if each entity in the tax consolidated group continues to be a standalone taxpayer in its own right. In addition to its own current and deferred tax amounts, the Company also recognises the current tax liabilities (or assets) and the deferred tax assets arising from unused tax losses and unused tax credits assumed from controlled entities in the tax consolidated group. Assets or liabilities arising under tax funding agreements with the tax consolidated entities are recognised as amounts receivable from or payable to other entities in the Group. Any difference between the amounts assumed and amounts receivable or payable under the tax funding agreement are recognised as a contribution to (or distribution from) wholly-owned tax consolidated entities. t r o p e R l a u n n A 8 1 0 2 3 0 1 Notes to the Consolidated Financial Statements SECTION 4: GROUP STRUCTURE 29. INTERESTS IN OTHER ENTITIES (a) Subsidiary companies The Consolidated Entity consists of a number of wholly or majority owned subsidiaries as set out below. The consolidated financial statements incorporate the assets and liabilities of all subsidiaries of the Company as at 30 June 2018 as set out below and the results for the year then ended. Place of incorporation Percentage of equity interest held by the Company Percentage of equity interest held by the non-controlling interests 2018 % 2017 % 2018 % 2017 % Material operating subsidiaries ERM Financial Services Pty Ltd ERM Gas Pty Ltd ERM Holdings Pty Ltd ERM Land Holdings Pty Ltd ERM Neerabup Power Pty Ltd ERM Neerabup Pty Ltd ERM Power Developments Pty Ltd ERM Power Generation Pty Ltd ERM Power International Pty Ltd ERM Power Investments Pty Ltd ERM Power Retail Pty Ltd ERM Power Trading LLC(i) Greensense Pty Ltd Lumaled Pty Ltd Oakey Power Holdings Pty Ltd Powermetric Metering Pty Ltd ERM Innovation Labs Pty Ltd(ii) Source Operations Group LLC Source Power & Gas LLC SPG Energy Group LLC Other non-material subsidiaries Braemar 3 Holdings Pty Ltd ERM Braemar 3 Pty Ltd ERM Braemar 3 Power Pty Ltd ERM Business Energy LLC ERM Gas WA01 Pty Ltd ERM Oakey Power Holdings Pty Ltd E.R.M. Oakey Power Pty Ltd ERM Power Services Pty Ltd ERM Power Utility Systems Pty Ltd ERM Wellington 1 Holdings Pty Ltd Queensland Electricity Investors Pty Ltd Richmond Valley Solar Thermal Pty Ltd (i) Formed 21 September 2016. (ii) Company name changed on 24 July 2018, formally SAGE Utility Systems Pty Ltd. R E W O P M R E 4 0 1 QLD QLD QLD QLD VIC VIC VIC VIC QLD QLD VIC USA WA NSW ACT NSW VIC USA USA USA QLD QLD QLD USA VIC NSW QLD VIC QLD QLD QLD QLD 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 29. INTERESTS IN OTHER ENTITIES (CONTINUED) Recognition and measurement Subsidiaries are fully consolidated from the date of acquisition, being the date on which the Group obtains control, and continue to be consolidated until the date that such control ceases. Control of an entity exists when the Group is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power to direct the activities of the entity. The existence and effect of potential voting rights that are currently exercisable or convertible are considered when assessing whether the Group controls another entity. The acquisition method of accounting is used to account for the acquisition of subsidiaries by the Group that were not previously under common control. On an acquisition-by-acquisition basis, the Group recognises any non-controlling interest in the acquiree either at fair value or at the non- controlling interest’s proportionate share of the acquiree’s net identifiable assets. Non-controlling interests in the results and equity of subsidiaries are shown separately in the consolidated income statement, statement of comprehensive income, statement of changes in equity and statement of financial position respectively. Intercompany balances, transactions and unrealised gains resulting from intra-group transactions with subsidiaries have been eliminated in full. Unrealised losses are also eliminated unless the transaction provides evidence of the impairment of the asset transferred. Changes in ownership interests The Group treats transactions with non-controlling interests that do not result in a loss of control as transactions with equity owners of the Group. A change in ownership interest results in an adjustment between the carrying amounts of the controlling and non-controlling interests to reflect their relative interests in the subsidiary. Any difference between the amount of the adjustment to non-controlling interests and any consideration paid or received is recognised in a separate reserve within equity attributable to owners of the Company. When the Group ceases to have control, joint control or significant influence, any retained interest in the entity is remeasured to its fair value with the change in carrying amount recognised in profit or loss. The fair value is the initial carrying amount for the purposes of subsequently accounting for the retained interest as an associate, jointly controlled entity or financial asset. In addition, any amounts previously recognised in other comprehensive income in respect of that entity are accounted for as if the Group had directly disposed of the related assets or liabilities. This may mean that amounts previously recognised in other comprehensive income are reclassified to profit or loss. Employee share trusts The Group has formed trusts to administer the Group’s employee share schemes. The trusts are consolidated, as the substance of the relationship is that the trusts are controlled by the Group. Shares held by the trusts are disclosed as treasury shares and deducted from contributed equity. t r o p e R l a u n n A 8 1 0 2 5 0 1 Notes to the Consolidated Financial Statements SECTION 4: GROUP STRUCTURE 29. INTERESTS IN OTHER ENTITIES (CONTINUED) (b) Significant joint operations – power station projects As at 30 June 2018 and 30 June 2017, the Group has the following interest in power station projects with other external parties. The Group has classified its investments in the NewGen Neerabup Partnership as a joint operation. The partners of the Partnership are jointly and severally liable for the liabilities of the partnership and under the partnership agreement are entitled to a proportionate share of Partnership’s assets. Neerabup Power Station: NewGen Power Neerabup Pty Ltd NewGen Neerabup Pty Ltd NewGen Neerabup Partnership Principle place of business Interest Held 2018 % 2017 % QLD QLD WA 50 50 50 50 50 50 The consolidated entity’s proportionate share of assets employed and liabilities incurred in power station projects classified as joint operations is summarised below. Consolidated 2018 $’000 2017 $’000 12,582 4,185 52 447 17,266 11,985 4,547 64 528 17,124 165,745 170,241 51 165,796 183,062 1,006 8,904 46 9,956 124,536 29,481 154,017 163,973 19,089 57 170,298 187,422 1,117 8,264 52 9,433 130,190 33,812 164,002 173,435 13,987 Current assets Cash and cash equivalents Trade and other receivables at amortised cost Inventories Other assets Total current assets Non-current assets Property, plant and equipment Intangible assets Total non-current assets Total assets Current liabilities Trade and other payables Borrowings – limited recourse Provisions Total current liabilities Non-current liabilities Borrowings – limited recourse Derivative financial instruments Total non-current liabilities Total liabilities Net assets R E W O P M R E 6 0 1 29. INTERESTS IN OTHER ENTITIES (CONTINUED) Capital expenditure commitments Estimated capital expenditure contracted for at balance date, not provided for but payable: – not later than one year – later than one year and not later than five years – later than five years Recognition and measurement Joint arrangements Consolidated 2018 $’000 2017 $’000 9 - - 9 14 - - 14 Under AASB 11, investments in joint arrangements are classified as either joint operations or joint ventures. The classification depends on the contractual rights and obligations of each investor, rather than the legal structure of the joint arrangement. The Group has joint operations but no material joint ventures. Joint operations The Group recognises its direct right to the assets, liabilities, revenues and expenses of joint operations and its share of any jointly held or incurred assets, liabilities, revenues and expenses. These have been incorporated in the financial statements under the appropriate headings. (c) Joint ventures In June 2016, the Group made a 33% investment in Energy Locals Pty Ltd for $1.5m, a company which provides a platform for members of communities to supply and charge each other energy. In May 2017, the Group acquired preference shares in Energy Locals for $1m. In May 2018 these shares were converted into ordinary shares and Energy Locals issued additional share capital to a third party investor, bringing the Group’s cash investment in the joint venture to 32.63% for $2.5m. (d) Interests in associate Name of entity Place of business/ country of incorporation Principle Activity 1st Energy Pty Ltd Australia Electricity sales to business and residential customers in New South Wales Measurement method Equity method % of ownership interest 2018 30 2017 30 During the 2017 financial year, the Group made a 30% investment in 1st Energy Pty Ltd (1st Energy) for $4.5m. The Group has representation on its board of directors and a consequent ability to participate in the financial and operating decisions. In the opinion of the directors, ERM Power has significant influence and 1st Energy is an associate of the Group. Recognition and measurement Associates are all entities over which the Group has significant influence but not control, generally accompanying a shareholding of between 20% and 50% of the voting rights. Investments in associates are accounted for in the consolidated financial statements using the equity method of accounting. The Group’s share of its associates’ post-acquisition profits or losses is recognised in the income statement, and its share of post-acquisition movements in reserves is recognised in reserves. The cumulative post-acquisition movements are adjusted against the carrying amount of the investment. Dividends receivable from associates are recognised in the consolidated financial statements by reducing the carrying amount of the investment. When the Group’s share of losses in an associate equals or exceeds its interest in the associate, including any other unsecured receivables, the Group does not recognise further losses, unless it has incurred obligations or made payments on behalf of the investment. Unrealised gains on transactions between the Group and its associates are eliminated to the extent of the Group’s interest in the associates. Unrealised losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred. Accounting policies of associates have been changed where necessary to ensure consistency with the policies adopted by the Group. Key judgments and estimates ERM Power has determined that it has significant influence, but not control or joint control, to govern the financial and operating policies of 1st Energy and accordingly the investment is accounted for as an associate. t r o p e R l a u n n A 8 1 0 2 7 0 1 Notes to the Consolidated Financial Statements SECTION 4: GROUP STRUCTURE 30. BUSINESS COMBINATION During the year ended 30 June 2018 the Group did not acquire any businesses. Recognition and measurement The acquisition method of accounting is used to account for all business combinations, regardless of whether equity instruments or other assets are acquired. The consideration transferred for the acquisition of a subsidiary comprises the fair values of the assets transferred, the liabilities incurred and the equity interests issued by the Group. The consideration transferred also includes the fair value of any asset or liability resulting from a contingent consideration arrangement and the fair value of any pre-existing equity interest in the subsidiary. Acquisition-related costs are expensed as incurred. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are, with limited exceptions, measured initially at their fair values at the acquisition date. On an acquisition-by-acquisition basis, the Group recognises any non-controlling interest in the acquiree either at fair value or at the non-controlling interest’s proportionate share of the acquiree’s net identifiable assets. The excess of the consideration transferred, the amount of any non-controlling interest in the acquiree and the acquisition-date fair value of any previous equity interest in the acquiree over the fair value of the Group’s share of the net identifiable assets acquired is recorded as goodwill. If those amounts are less than the fair value of the net identifiable assets of the subsidiary acquired and the measurement of all amounts has been reviewed, the difference is recognised directly in profit or loss as a discount on acquisition. Where settlement of any part of cash consideration is deferred, the amounts payable in the future are discounted to their present value as at the date of exchange. The discount rate used is the entity’s incremental borrowing rate, being the rate at which a similar borrowing could be obtained from an independent financier under comparable terms and conditions. Contingent consideration is classified either as equity or a financial liability. Amounts classified as a financial liability are subsequently remeasured to fair value with changes in fair value recognised in profit or loss. R E W O P M R E 8 0 1 31. DISCONTINUED OPERATIONS On 23 August 2018, the Group publicly announced the decision of its Board of Directors to sell the US business Source Power & Gas. A plan to sell was approved and actioned in June 2018. The sale is expected to be completed during the first half of FY2019. At 30 June 2018, the US business was classified as a disposal group held for sale and as a discontinued operation. The results of the US business are presented below and include the results of the US residential business for the comparative year, which was sold during FY2017: (a) Financial performance and cash flow information The financial performance and cash flow information presented reflects the operations for the year. Revenue Expenses EBITDAF Gain on sale of customer contracts Net fair value gain / (loss) on financial instruments designated at fair value through profit or loss Note 31(b) Depreciation and amortisation Net finance costs Loss before tax Income tax (expense) / benefit Net loss from discontinued operations Exchange differences on translation of discontinued operations Other comprehensive income / (loss) from discontinued operations Total comprehensive loss from discontinued operations Net cash inflow from operating activities Net cash outflow from investing activities Net cash outflow from financing activities Net (decrease) / increase in cash generated by the discontinued operations Revenue Major product / service lines Sale of electricity Timing of revenue recognition Recognised over time 2018 $’000 529,719 2017 $’000 419,186 (529,546) (423,920) 173 - 9,571 (16,687) (14,729) (21,672) (12,296) (4,734) 10,851 (16,391) (11,214) (6,604) (28,092) 7,762 (33,968) (20,330) 1,310 1,310 (1,342) (1,342) (32,658) (21,672) 16,310 (11,692) (14,958) (10,340) 529,719 529,719 529,719 529,719 21,644 (795) (6,557) 14,292 419,186 419,186 419,186 419,186 t r o p e R l a u n n A 8 1 0 2 9 0 1 Notes to the Consolidated Financial Statements SECTION 4: GROUP STRUCTURE 31. DISCONTINUED OPERATIONS (CONTINUED) (b) Details of the sale of the US residential customer contract assets Consideration received or receivable: Cash Total disposal consideration Carrying amount of net assets sold Gain on sale before income tax and reclassification of foreign currency translation reserve Reclassification of foreign currency translation reserve Income tax expense on gain Gain on sale after income tax Consolidated 2018 $’000 2017 $’000 - - - - - - - 15,806 15,806 (4,955) 10,851 (205) (5,532) 5,114 (c) Assets and liabilities of disposal group classified as held for sale The following assets and liabilities were reclassified as held for sale in relation to the US discontinued operation as at 30 June 2018: Assets classified as held for sale Cash and cash equivalents Trade and other receivables at amortised cost Inventories Other assets Derivative financial instruments Leased assets Property, plant and equipment Intangible assets Deferred tax assets Total assets of disposal group held for sale Liabilities directly associated with assets classified as held for sale Trade and other payables Lease liabilities Provisions Derivative financial instruments Total liabilities of disposal group held for sale Note Consolidated 2018 $’000 12,822 74,000 14 837 5,890 990 769 64,795 3,710 163,827 94,915 1,189 39,181 15,352 150,637 18 15 16 21 20 As at 30 June 2018, the Group has classified $3.4m intangible assets as held for sale and $1.5m trade and other payables as liabilities associated with the Business Energy Australia operations single site SME customer contracts acquisition costs. A decision to sell these sites was finalised in June 2018. R E W O P M R E 0 1 1 Notes to the Consolidated Financial Statements SECTION 5: EMPLOYEE REMUNERATION 32. KEY MANAGEMENT PERSONNEL Key management personnel compensation Short-term employee benefits Long-term employee benefits Post-employment benefits Share-based payments Consolidated 2018 $ 2017 $ 6,961,679 6,760,826 39,402 221,887 65,402 223,212 1,366,422 1,327,333 8,589,390 8,376,773 Detailed remuneration disclosures are provided in the Remuneration Report. 33. SHARE BASED PAYMENTS The Company provides benefits to employees (including the CEO and Senior Executives) of the Group in the form of share-based payments, whereby selected employees who are invited by the Board render services in exchange for shares or options or rights over shares. The objective of the Long Term Incentive Scheme (LTI) is to provide incentives to focus on long term shareholder returns. These incentive awards have previously been granted by way of offers to participate in both the Employee Share Trust (EST) and the Long Term Incentive Option Trust (LTIOT). The expense arising from these transactions is shown in note 5. The Group operates a number of share-based payment plans. A description of each type of share-based payment arrangement that existed at any time during the period is described below. The fair value of options and rights granted under equity-settled share based arrangements are measured at grant date and spread over the vesting period through a charge to employee benefit expense in the income statement and a corresponding increase in the share-based payments reserve in equity. The fair value of share based payments takes into account market performance conditions, but excludes the impact of any non-market vesting conditions. Non-market vesting conditions are included in the assumptions about the number of shares that are expected to be vested. Upon vesting, the relevant amount in the share-based payments reserve is transferred to contributed equity. STIST and EST (formerly the LTIST) The Company previously received approval of these employee incentive plans by shareholders at the 2016 AGM. Shares are acquired by a trustee who holds those shares on behalf of participants. The shares are acquired by the trustee either subscribing for new shares or purchasing shares on market. Participants hold their interest through units, where one unit represents one share. Participants apply for a loan to acquire units in the trust at the prevailing market value of the shares. A participant may instruct the trustee how to exercise their vote in the case of a poll at a meeting of the Company. Vesting conditions, if any, may be a combination of service and performance hurdles, as determined by the directors. If the participant’s employment ceases prior to the units vesting, the Board will determine if the participant’s units are forfeit or, for redundancy, death or permanent disability, or in circumstances that the Board determines appropriate, continue to be held to the end of the performance period at which time the proportion to vest will be re-assessed. Early vesting may occur on a change of control of the Company, being a material change in the composition of the Board initiated as a result of a change of ownership of shares and the purchaser of the shares requiring (or agreeing with other shareholders to require) that change in Board composition, or in other circumstances that the Board determines appropriate. Any units issued without market based vesting conditions are valued at the external market price at the time of issue and are not valued using a Monte Carlo simulation or other methodology. At 30 June 2018, 7,531,156 units remained outstanding not yet vested (2017: 7,648,455). t r o p e R l a u n n A 8 1 0 2 1 1 1 Notes to the Consolidated Financial Statements SECTION 5: EMPLOYEE REMUNERATION 33. SHARE BASED PAYMENTS (CONTINUED) Key judgments and estimates Valuation of shares granted under LTI awards The fair value of shares granted under the EST with market based vesting conditions is determined using a Monte Carlo simulation (using a Black-Scholes framework). The model inputs for restricted shares granted are shown in the table below. Assessed fair value per share at grant date(i) Number of units allocated under the plan during the financial year(ii) Share price at grant date Exercise price Expected price volatility of the Company’s shares based on historic volatility Risk free interest rate Expected vesting date Dividend yield FY2018 grants $0.63 - $0.64 2,433,169 $1.20 - $1.29 Nil 39% 1.94% - 2.10% FY2017 grants $0.57 - $0.68 2,829,195 $0.84 - $1.13 Nil 38% - 39% 1.52% - 1.74% 3 years after issue 2 - 3 years after issue 5.45% - 5.83% 10.62% - 14.29% Proportion subject to vesting on satisfaction of total security holder return (TSR) performance(ii) 100% 100% (i) Valued using a Monte Carlo simulation. (ii) Certain grants may have other service based conditions in lieu of a TSR component. For those grants with a TSR condition, vesting is based 100% on meeting both TSR and service conditions. The performance hurdle will only be satisfied where the TSR value is positive. If the TSR value is negative, the performance hurdle will not be satisfied, and the underlying shares in the LTIST will not vest. LTIOT Options were granted during the 2011 financial year. No options have been granted subsequent to the 2011 financial year. Participants were issued units at the prevailing market value of the options. The assessed fair value at grant date of options granted during the year ended 30 June 2011 was 10.43 cents. The fair value at grant date was determined using a Black-Scholes option pricing model that takes into account the exercise price, the term of the option, the share price at grant date and expected price volatility of the underlying share, the expected dividend yield and the risk free interest rate for the term of the option. Early vesting and the consequences of cessation of employment prior to vesting are identical to the LTIST as described above. Details of movements in the option plan is set out below. Financial year 2011 2011 Total Grant Date Expiry date 1/11/2010 1/11/2017 8/11/2010 8/11/2017 Exercise price $2.75 $2.75 Balance at start of the year Number Granted during the year Number Forfeited during the year Number Options expired during the year Number Balance at end of the year Number Vested and exercisable at end of the year Number 961,874 242,706 1,204,580 - - - 128,750 833,124 - 242,706 128,750 1,075,830 - - - - - - Other awards The Company may offer awards outside of the standard incentive plans. Performance Rights have been granted as part of an employee retention strategy. The Performance Rights are subject to a vesting period and will be satisfied, at the Board’s discretion, in cash or shares, subject to continuous full-time employment with the Company. The vesting value will be the number of Performance Rights held, multiplied by the higher of either the notional issue price, or the 10 day VWAP at the vesting date. Details of the Performance Rights issues are set out below. Financial year 2016 2015 2014 Grant Date 21/12/2015 23/9/2014 16/8/2013 Vesting date 6/1/2019 23/9/2019 16/8/2018 Number 468,232 280,114 92,285 Notional issue price $1.538 $1.785 $2.709 R E W O P M R E 2 1 1 Notes to the Consolidated Financial Statements SECTION 6: OTHER DISCLOSURE ITEMS 34. COMMITMENTS AND CONTINGENCIES (a) Capital expenditure commitments Estimated capital expenditure contracted for at balance date, not provided for but payable (including share of associates and joint ventures): – not later than one year – later than one year and not later than five years – later than five years Consolidated 2018 $’000 199 - - 199 2017 $’000 7,517 138 - 7,655 (b) Contingent liabilities Details of contingent liabilities are set out below. The directors are of the opinion that provisions are not required in respect of these items as it is not probable that a future sacrifice of economic benefits will be required or the amount is not capable of reliable measurement. Bank guarantees - Australian Energy Market Operator and other counterparties Bank guarantees - Lease arrangements Futures margin deposits Security deposits Bank guarantees - Western Power Note Consolidated (i) (ii) (iii) (iv) (v) 2018 $’000 2017 $’000 221,845 208,162 2,365 141,749 10,155 300 2,915 - 1,345 300 376,414 212,722 (i) (ii) (iii) (iv) (v) The Group has provided bank guarantees in favour of the Australian Energy Market Operator to support its obligations to settle electricity purchases from the National Electricity Market. Bank guarantees have also been provided to various counterparties in relation to electricity derivatives. A portion of the guarantees are supported by term deposits. $180m of the bank guarantees are supported by non-cash backed guarantees in 2018 (2017: $150m). The Group has provided bank guarantees in relation to lease arrangements for premises in Brisbane, Sydney, Melbourne and Perth. These guarantees are supported by term deposits. Futures margin deposits represent cash lodged with the Group’s futures clearing brokers. The deposits are in relation to various futures contracts on the Australian Securities Exchange and Intercontinental exchange and may be retained by the clearing brokers in the event that the Group does not meet its contractual obligations. Security deposits represent interest bearing cash lodged as eligible credit support with various counterparties to the Group’s electricity derivative contracts and may be retained by those counterparties in the event that the Group does not meet its contractual obligations. The Group has provided a bank guarantee in favour of Western Power. This can be called upon if the Neerabup partnership fails to pay its monthly transmission invoices. t r o p e R l a u n n A 8 1 0 2 3 1 1 Notes to the Consolidated Financial Statements SECTION 6: OTHER DISCLOSURE ITEMS 35. RELATED PARTY DISCLOSURES Transactions with Sunset Power International Pty Ltd A subsidiary of the Company, ERM Power Retail Pty Ltd (“ERM”), has entered into a long term electricity swap contract with the Vales Point power station in New South Wales to hedge electricity purchases in relation to its eastern state electricity load from the NEM. The power station is 100% owned by Sunset Power International Pty Ltd (“SPI”) which in turn is owned and controlled by Trevor St Baker. The swap contract was entered into on 20 November 2015 and finalised in February 2016. The contract terms and conditions are no more favourable to SPI than those that it is reasonable to expect ERM would have adopted if dealing at arms-length with an unrelated person and are not adverse to ERM. The components of the contract are as follows: • • • • • Firm flat swap sold to ERM priced at market prices (based on market observed ASX Energy contract prices) Firm peak swap sold to ERM priced at market prices (based on market observed ASX Energy contract prices) Call option for ERM to purchase additional off-peak swaps Call option for ERM to purchase additional peak swaps Reallocation and capital efficiency payments over the term of the contract ERM have access to the respective hedge volumes under the agreement out to 31 December 2022. The total premiums payable for the option over the period 1 July 2018 to 31 December 2022 is $4.3m. All accounts payable are within payment terms of the agreement and no impairment loss has been recognised during the period in relation to the transaction. The agreement expires on 31 December 2022 and under the agreement ERM is expected to hedge approximately 21% of ERM’s electricity load sales over the term of the agreement prior to exercise of any of the available options. As at 30 June 2018 net assets of $54.7m have been recognised in relation to the above transaction comprising the following: • • • MTM of electricity swaps of $19.1m of which $31.5m is current(i) and ($12.4m) is non-current MTM of electricity options of $23.2m of which $12.5m is current(i) Accrued income of $12.4m During the year ended 30 June 2018 total net receipts of $120.0m were recognised in profit and loss in respect of the swap agreement. Under the terms of the swap agreement SPI has posted a bank guarantee in favour of ERM for $8.5m. The guarantee is accessible under a range of financial risk events. (i) Refer Note 23 for details of fair value measurement. Other related party transactions In the normal course of business the Company enters into the following transactions with related parties: • • • Project management and operations management fees are charged to jointly controlled entities; Interest is paid on shareholder loans; and Directors personal travel insurance is provided under standard terms of a directors and officers business travel insurance policy taken out by the Company. Cover under this policy for directors personal travel is provided by the insurer at no additional cost to the Company. There is no allowance account for impaired receivables in relation to any outstanding balances, and no expense has been recognised in respect of impaired receivables due from related parties. Transactions with jointly operated and joint venture entities: Movements in net loans advanced / (repaid) Current trade receivables balance Project fees and operations management fees Electricity derivatives settled (loss) / profit Transactions with associates: Accrued income balance Electricity derivatives settled profit Refer note 29(b) for details of significant jointly controlled entities and note 29(d) for details of associates. Consolidated 2018 $ 332 94,311 2017 $ (382) 93,618 2,659,737 2,562,785 (169,177) 708 192,875 300,669 3,316,928 1,479,873 R E W O P M R E 4 1 1 36. AUDITORS’ REMUNERATION Amounts received or due and receivable by PricewaterhouseCoopers Australia for: An audit or review of the financial report of the entity and any other entity in the Group Amounts received or due and receivable by PricewaterhouseCoopers Australia for non-audit services: Other procedures in relation to the entity and any other entity in the consolidated Group Total remuneration of PricewaterhouseCoopers Australia Consolidated 2018 $ 2017 $ 500,000 500,000 555,000 555,000 - - 93,328 93,328 500,000 648,328 Amounts received or due and receivable by network firms of PricewaterhouseCoopers Australia for: An audit or review of the financial report of the entity and any other entity in the Group Total remuneration of network firms of PricewaterhouseCoopers Australia 148,830 148,830 143,006 143,006 37. EVENTS AFTER THE REPORTING PERIOD Since 30 June 2018 there have been no other matters or circumstances not otherwise dealt with in the Financial Report that have significantly or may significantly affect the Group. 38. BASIS OF PREPARATION These financial statements cover ERM Power Limited the consolidated entity (“Group” or “Consolidated Entity”) consisting of ERM Power Limited (the “Company”) and its subsidiaries. The report is presented in Australian dollars. The Company is incorporated and domiciled in Australia. Its registered office and place of business is Level 52, 111 Eagle Street, Brisbane, Queensland 4000. A description of the nature of the Group’s operations and of its principal activities is included in the review of operations and activities in the Directors’ Report on pages 40 to 42. This report was authorised for issue by the directors on 23 August 2018. The principal accounting policies adopted in the preparation of the financial report are set out below. These policies have been consistently applied to all the years presented, unless otherwise stated. The Company is a for-profit entity for the purpose of preparing the financial statements. This general purpose financial report has been prepared in accordance with Australian Accounting Standards, other authoritative pronouncements of the Australian Accounting Standards Board and the Corporations Act 2001. Compliance with IFRS The consolidated financial statements of the Group comply with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB). Historical cost convention These financial statements have been prepared under the historical cost convention, as modified by the revaluation of financial assets and liabilities (including derivative financial instruments) at fair value through profit and loss and other comprehensive income. Early adoption of Australian Accounting Standards The Group has not elected to apply any pronouncements before their operative date in the annual reporting period beginning 1 July 2017. Changes in accounting policies The Group has not had to change its accounting policies as the result of new or revised accounting standards which became effective for the annual reporting period commencing on 1 July 2017. t r o p e R l a u n n A 8 1 0 2 5 1 1 Notes to the Consolidated Financial Statements SECTION 6: OTHER DISCLOSURE ITEMS 38. BASIS OF PREPARATION (CONTINUED) (a) Foreign currency translation Functional and presentation currency Items included in the financial statements of each of the Group’s entities are measured using the currency of the primary economic environment in which the entity operates (“the functional currency”). The consolidated financial statements are presented in Australian dollars, which is the Company’s functional and presentation currency. Transactions and balances Foreign currency transactions are translated into the functional currency at the rate of exchange at the date of the transaction. Foreign exchange gains and losses resulting from the settlement of such transactions, and from the translation at year end exchange rates of monetary assets and liabilities denominated in foreign currencies, are recognised in the income statement, except when deferred in equity as qualifying cash flow hedges. Group companies The results and financial position of foreign operations (none of which has the currency of a hyperinflationary economy) that have a functional currency different from the presentation currency are translated into the presentation currency as follows: • • • assets and liabilities for each balance sheet presented are translated at the closing rate at the date of that balance sheet, income and expenses for each income statement and statement of comprehensive income are translated at average exchange rates (unless this is not a reasonable approximation of the cumulative effect of the rates prevailing on the transaction dates, in which case income and expenses are translated at the dates of the transactions), and all resulting exchange differences are recognised in other comprehensive income. On consolidation, exchange differences arising from the translation of any net investment in foreign entities, and of borrowings and other financial instruments designated as hedges of such investments, are recognised in other comprehensive income. When a foreign operation is sold or any borrowings forming part of the net investment are repaid, the associated exchange differences are reclassified to profit or loss, as part of the gain or loss on sale. Goodwill and fair value adjustments arising on the acquisition of a foreign operation are treated as assets and liabilities of the foreign operation and translated at the closing rate. (b) Goods and services tax (GST) Revenues, expenses and assets are recognised net of the amount of associated GST, unless the GST incurred is not recoverable from the taxation authority. In this case it is recognised as part of the cost of acquisition of the asset or as part of the expense. Receivables and payables are stated inclusive of the amount of GST receivable or payable. The net amount of GST recoverable from, or payable to, the taxation authority is included with other receivables or payables at the balance date. Cash flows are presented on a gross basis. The GST components of cash flows arising from investing or financing activities which are recoverable from, or payable to the taxation authority, are presented as operating cash flows. (c) Rounding of amounts The Group is of a kind referred to in legislative instrument 2016/191, issued by the Australian Securities and Investments Commission, relating to the ‘’rounding off’’ of amounts in the financial statements. Amounts in the financial statements have been rounded off in accordance with that class order to the nearest thousand dollars, or in certain cases, the nearest dollar. (d) New accounting standards and interpretations Certain new accounting standards and interpretations have been published that are not mandatory for 30 June 2018 reporting periods. Unless stated otherwise below, the Group is currently in the process of assessing the impact of these standards and amendments and is yet to decide whether to early adopt any of the new and amended standards. AASB 2014-10 Sale or contribution of assets between an investor and its associate or joint venture (effective from 1 January 2018). The amendments clarify the accounting treatment for sales or contribution of assets between an investor and its associates or joint ventures. They confirm that the accounting depends on whether the contributed assets constitute a business or an asset. AASB 2016-5 Classification and Measurement of Share-based Payment Transactions (effective from 1 January 2018). Amendments were made to AASB 2 Share-based Payment which clarify how to account for cash-settled share-based payments with performance conditions, modifications that change a cash-settled arrangement to an equity-settled arrangement, and equity-settled awards that include a ‘net settlement’ feature which requires employers to withhold amounts to settle the employee’s tax obligations. Interpretation 22 Foreign Currency Transactions and Advance Consideration (effective from 1 January 2018). The interpretation clarifies how to apply the standard on foreign currency transactions, AASB 121, when an entity pays or receives consideration in advance for foreign currency-denominated contracts. AASB Interpretation 23 Uncertainty over Income Tax Treatments (effective from 1 January 2019). The Interpretation clarifies how to apply the recognition and measurement requirements in AASB 112 when there is uncertainty over income tax treatments. AASB 2018-1 Annual Improvements 2015–2017 Cycle (effective from 1 January 2019). This standard makes amendments to AASB 3 Business Combinations, AASB 11 Joint Arrangements, AASB 112 Income Taxes and AASB 123 Borrowing Costs. AASB 2018 -2 Amendments to AASB 19 – plan amendment, curtailment or settlement (effective from 1 January 2019). The AASB has issued amendments to the guidance in AASB 119 Employee Benefits in connection with accounting for plan amendments, curtailments and settlements. There are no other standards that are not yet effective and that are expected to have a material impact on the entity in the current or future reporting periods and on foreseeable future transactions. R E W O P M R E 6 1 1 Director’s Declaration In the opinion of the directors of ERM Power Limited (“Company”): (a) the financial statements and notes set out on pages 57 to 116 are in accordance with the Corporations Act 2001, including: i. giving a true and fair view of the financial position of the consolidated entity as at 30 June 2018 and of its performance for the year then ended, and ii. complying with Australian Accounting Standards (including the Australian Accounting Interpretations), the Corporations Regulations 2001 and other mandatory professional reporting requirements. (b) the financial report complies with International Financial Reporting Standards as disclosed in note 38; (c) there are reasonable grounds to believe that the Company will be able to pay its debts as and when they become due and payable; Note 38 confirms that the financial statements also comply with International Financial Reporting Standards as issued by the International Accounting Standards Board. The directors have been given the declarations by the chief executive officer and chief financial officer required by section 295A of the Corporations Act 2001. Signed in accordance with a resolution of the directors: Tony Bellas Chairman 23 August 2018 t r o p e R l a u n n A 8 1 0 2 7 1 1 R E W O P M R E 8 1 1 PricewaterhouseCoopers, ABN 52 780 433 757480 Queen Street, BRISBANE QLD 4000, GPO Box 150, BRISBANE QLD 4001T: +61 7 3257 5000, F: +61 7 3257 5999, www.pwc.com.auLiability limited by a scheme approved under Professional Standards Legislation.Independent auditor’s reportTo the members of ERM Power LimitedReport on the audit of the financial reportOur opinionIn our opinion:The accompanying financial report of ERM Power Limited (the Company) and its controlled entities (together the Group) is in accordance with the Corporations Act 2001, including:(a)giving a true and fair view of the Group's financial position as at 30 June 2018 and of its financial performance for the year then ended (b)complying with Australian Accounting Standards and the Corporations Regulations 2001.What we have auditedThe Group financial report comprises:•the consolidated statement of financial position as at 30 June 2018•the consolidated statement of comprehensive income for the year then ended•the consolidated statement of changes in equity for the year then ended•the consolidated statement of cash flows for the year then ended•the consolidated income statement for the year then ended•the notes to the consolidated financial statements, which include a summary of significant accounting policies•the directors’ declaration.Basis for opinionWe conducted our audit in accordance with Australian Auditing Standards. Our responsibilities under those standards are further described in the Auditor’s responsibilities for the audit of the financial reportsection of our report.We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.IndependenceWe are independent of the Group in accordance with the auditor independence requirements of the Corporations Act 2001and the ethical requirements of the Accounting Professional and Ethical Standards Board’s APES 110 Code of Ethics for Professional Accountants(the Code) that are relevant to our audit of the financial report in Australia. We have also fulfilled our other ethical responsibilities in accordance with the Code. t r o p e R l a u n n A 8 1 0 2 9 1 1 Our audit approachAn audit is designed to provide reasonable assurance about whether the financial report is free from material misstatement. Misstatements may arise due to fraud or error. They are considered material if individually or in aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of the financial report.We tailored the scope of our audit to ensure that we performed enough work to be able to give an opinion on thefinancial report as a whole, taking into account the geographic and management structure of the Group, its accounting processes and controls and the industry in which it operates.The Group operates across Australia and the United States of America, with its head office finance function based in Brisbane and its US finance function for the Source Power and Gas business based in Houston, United States of America.Materiality•For the purpose of our audit we used overall Group materiality of $2.4million which represents approximately 2.5% of the Group's earnings before interest, tax, depreciation, amortisation and net fair value gains / losses on financial instruments designated at fair value through profit (EBITDAF).•We applied this threshold, together with qualitative considerations, to determine the scope of our audit and the nature, timing and extent of our audit procedures and to evaluate the effect of misstatements on the financial report as a whole.•We chose Group EBITDAF as the benchmark because, in our view, it is the metric against which the performance of the Group is most commonly measured.•We utlised a 2.5% threshold based on our professional judgement.Audit Scope•Our audit focused on where the Groupmade subjective judgements; for example, significant accounting estimates involving assumptions and inherently uncertain future events.•In establishing the overall approach to the Group audit, we determined the type of audit work that needed to be performed.Full scope audit procedures were performed over the Australian operations and the Source Power and Gas business, assisted by local component auditors in Houston.•To be satisfied that sufficient audit evidence has been obtained on the Source Power and Gas business for our opinion on the Group financial report as a whole, the group audit engagement team had active dialogue throughout the year with the local component auditors in Houston, including issuing written instructions, receiving formal interoffice reporting, as well as attending final audit clearance meetings with local management in Houston. R E W O P M R E 0 2 1 Key audit mattersKey audit matters are those matters that, in our professional judgement, were of most significance in our audit of the financial report for the current period. The key audit matters were addressed in the context of our audit of the financial report as a whole, and in forming our opinion thereon, and we do not provide a separate opinion on these matters. Further, any commentary on the outcomes of a particular audit procedure is made in that context. We communicated the key audit matters to the Audit and Risk Committee.Key audit matterHow our audit addressed the key audit matterEnergy derivatives accounting treatment, valuation and disclosure(Refer to note 13Derivative financial instruments) The Group enters into various types of forward energyderivative instruments to manage exposure tofluctuations in electricity prices.As at 30 June 2018, in the financial report, the energyderivative financial assets totalled$99m, energyderivative financial liabilities totalled$84m and net fairvalue losson energy derivatives impactingprofit totalled$109m.Given the level of judgement associated with theaccounting treatment and valuation of theenergy derivatives, and the financial significance of the derivativesbalances, we considered this to be a key audit matter.Some of the key areas of judgement by the Group included:•The designation, and resulting accountingtreatment, of instruments as being hedge accountedor not hedge accounted.•The classification of fair value gains or losses priorto settlement depending on whether the instrumentis hedge accounted or not hedge accounted.•The accounting treatment if instruments are settledat a date earlier than the original maturity date, asthere is a difference in timing of the recognition ofgains or losses in cost of sales dependent onwhether the instrument is hedge accounted or nothedgeaccounted.•The judgement applied in selecting the appropriatevaluation techniques, and associated inputassumptions, for each type of energy derivativefinancial instrument entered into by the Group.Our procedures in relation to energy derivatives’accounting treatment, valuation and disclosure included,amongst others:•Obtained an understanding of the Group’s internalrisk management procedures and the systems andcontrols around the origination and maintenance ofcomplete and accurate information relating toderivative contracts.•Where appropriate,performed tests of key controlsrelating to the settlement of derivative contracts.•Tested a sample of derivative contracts at the year-enddate by obtaining third party confirmations of thecontract terms.•With the assistance of PwC valuation expertswe assessedthe valuation of a sample of derivativecontracts at the year-end date where the Group usedvaluation models.We evaluated the valuationmethodology applied and theincorporation of the contractterms and key assumptions intothe valuationmodels, including market observable future priceassumptions and discount rates.•Independently recalculated the valuation of a sampleof less complex instruments based on availablemarket data.•Evaluated the Group’s assessment of credit riskassumptions applied in the valuation models asrequired by the Australian Accounting Standards.•Assessed the Group’s hedge designationdocumentation and effectiveness testing for a sampleof derivatives. t r o p e R l a u n n A 8 1 0 2 1 2 1 Key audit matterHow our audit addressed the key audit matterFor further details of the accounting policy adopted bythe Group and the financial impact, refer to note 13, note14, note 22and note 23in the financial report.•Evaluated the Group’s assessment of the accountingtreatment and classification of settled derivativeagreements with a settlement date at a date earlierthan the original settlement date.•Evaluated the adequacy of the disclosures made in the notesto the financial report, with reference to the requirements of the Australian Accounting Standards. Sunset Power International derivative agreement(Refer to note 35Related party disclosuresand note 13Derivative financial instruments)The Group hasa significant long term electricityderivative contract(contract)with Vales Point power station, in New South Wales,to hedge electricity purchases in relation to its eastern state electricity loadfrom the National Energy Market. The power station is100% owned by Sunset Power International Pty Ltd, whichisowned andcontrolled by a related party of ERM.The related party disclosures in note 35of the financial reportsets out the keyterms of the contractual arrangement.Judgement is required by the Group in estimating the fairvalue of the derivative contract, dueto the life of thecontract extending beyond a period that available marketdata can be obtained. The fair value of the derivative contract is therefore estimated through the application of specific valuation techniques and assumptions. On inception ofthe contract, a difference was identifiedbetween the premiums paid for the contract and theestimated fair value of the contract. Refer to note 23fortreatment of the difference (the day one gain).We considered this a key audit matter, given the importance of the contract to the financialposition and performance of the Group, the level ofjudgement required in the valuationof the contract, and related party naturethereof.We performed the following procedures, amongstothers:•With the assistance of PwC valuation experts, we assessed the valuation of the derivative contract attheyear-end date.We evaluated the valuationmethodologyapplied and the incorporation of the contractterms and the key assumptions into the valuationmodel, including future priceassumptions anddiscount rates.•Tested the termsof the derivative contractat the year-end date by obtaining writtenconfirmations of the contract terms.•Assessed whether the accounting treatment of the day one gain is consistent with that established at inception.•Evaluated the Group’s assessment of credit riskassumptions applied in the valuation model asrequired by the Australian Accounting Standards.•Assessed the consistency of the related partydisclosures with Australian Accounting Standardsby agreeing the disclosures to contractual terms, thederivative valuation model and relateddocumentation. R E W O P M R E 2 2 1 Key audit matterHow our audit addressed the key audit matterClassification and valuation of the Source Power and Gas held for sale asset(Refer to note 31Discontinued operation) In June 2018, the directors of the Companydecided to divest theSource Power and Gas operations,in the US. As at 30 June 2018, the operations to be divested are classifiedin the financial reportas held for sale and discontinued operations,asthe Group considerit is highly probable thatthe carrying value will be recovered principally through a sales transactionwithin 12 months from the classification.As required by the Australian Accounting Standards,the assets held for sale are measured at the lower of carrying value and estimated fair value less costs to sell. We considered this a key audit mattergiventhe significant level of judgementand estimates involved in assessing the classification and measurementof assetsand liabilitiesin the held for salediscontinued operation,as well as the materiality of theassetand liabilities on the Groupsfinancial position.Our procedures in relation to the valuation and classificationof the Source Power and Gas held forsalediscontinued operationassets and liabilities included,amongst others:•Assessed the appropriateness of the Group’s classification of Source Power and Gas as held for sale and discontinued operations.•Assessed the accuracy of the allocationof assets and liabilities separately classified as held for sale in the statement of financial position.•Evaluated the measurementof the assets and liabilities classified as held for sale at the lower of carrying value and fair value less cost to sell.•Evaluated the Group’s key assumptions and estimates in relation to the calculation of the fair value less costs of disposalby comparing to indicative bidsand contracts.•Evaluated the adequacy of the disclosures made in note31to the financialreport in light of the requirements ofAustralian Accounting Standards.Recoverability of deferred tax asset relating to tax losses(Refer to note 31Discontinued operationand note21 Deferred Tax Assets and Liabilities) At 30 June 2018 the Group has recorded a deferred tax asset of $3.7m relating to tax losses incurred in relation to Source Power and Gas. The recoverability of this deferred tax asset is dependent on the generation of sufficient future taxable income that is expected to be generated uponthe sale of Source Power and Gas.The Group has derecognised $10.3m of deferred tax assets relating to tax losses and other deferred tax assets as they areno longerexpected to be recovered.Recoverability of the deferred tax asset relating to tax losses was a key audit matter due to the material nature of the balanceand theimpact of the derecognitionon the financial resultsas well as the judgementsrequired inestimating thetaxable incomeon the sale of Source Power and Gas.We performed the following audit procedures, amongst others:•Evaluated the Group’s key assumptions and estimates used in the calculation of the estimated taxable incomeon the sale of Source Power and Gas operations.•Assessed the mathematical accuracy of the amount of the deferred tax asset derecognised.•Evaluated the adequacy ofthe deferred tax balance disclosures, made in note 21of the financial report, in view of the requirements of Australian Accounting Standards. t r o p e R l a u n n A 8 1 0 2 3 2 1 Other informationThe directors are responsible for the other information. The other information comprises the information included in the Group’s annual report for the year ended 30 June 2018, including the Operating and Financial Review, Corporate Social Responsibility, Board of Directors, the Directors’ Report and Corporate Information, but does not include the financial report and our auditor’s report thereon.Our opinion on the financial report does not cover the other information and accordingly we do not express any form of assurance conclusion thereon. In connection with our audit ofthe financial report, our responsibility is to read the other information identified above and, in doing so, consider whether the other information is materially inconsistent with the financial report or our knowledge obtained in the audit, or otherwise appears to be materially misstated.If, based on the work we have performed, we conclude that there is a material misstatement of this other information, we are required to report that fact. We have nothing to report in this regard. Responsibilities of the directors for the financial reportThe directors of the Company are responsible for the preparation of the financial report that gives a true and fair view in accordance with Australian Accounting Standards and Corporations Act 2001 and for such internal control as the directors determine is necessary to enable the preparation of the financial report that gives a true and fair view and is free from material misstatement, whether due to fraud or error. In preparing the financial report, the directors are responsible for assessing the ability of the Group to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless the directors either intend to liquidate the Group or to cease operations, or have no realistic alternative but to do so.Auditor’s responsibilities for the audit of the financial reportOur objectives are to obtain reasonable assurance about whether the financial report as a whole is free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with the Australian Auditing Standards will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of the financial report. A further description of our responsibilities for the audit of the financial report is located at the Auditing and Assurance Standards Board website at: http://www.auasb.gov.au/auditors_responsibilities/ar1.pdf. This description forms part of our auditor's report. R E W O P M R E 4 2 1 Report on the remuneration reportOur opinion on the remuneration reportWe have audited the remuneration report included inpages43to54of the directors’reportfortheyear ended 30June2018.In our opinion, the remuneration report of ERM Power Limited for the year ended 30 June 2018 complies with section 300A of the Corporations Act 2001.ResponsibilitiesThe directors of the Company are responsible for the preparation and presentation of the remuneration report in accordance with section 300A of the Corporations Act 2001. Our responsibility is to express an opinion on the remuneration report, based on our audit conducted in accordance with Australian Auditing Standards. Matters relating to the electronic presentation of the audited financial reportThis auditor’s report relates to the financial report of ERM Power Limited for the year ended 30 June 2018 included on ERM Power Limited's web site.The directors of the Company are responsible for the integrity of ERM Power Limited's web site.We have not been engaged to report on the integrity of this web site. The auditor’s report refers only to the financial report named above. It does not provide an opinion on any other information which may have been hyperlinked to/from the financial report. If users of this report are concerned with the inherent risks arising from electronic data communications they are advised to refer to the hard copy of the audited financial report to confirm the information included in the audited financial report presented on this web site.PricewaterhouseCoopersMichael ShewanBrisbanePartner23August 2018 Share and shareholder information SHARE AND SHAREHOLDER INFORMATION Twenty largest shareholders The following table sets out the 20 largest shareholders of ERM Power Limited (Company), when multiple holdings are grouped together, and the percentage each holds of the 255,421,056 shares on issue as at 22 August 2018. Shareholders Number of Shares Percentage of issued shares 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 St Baker Energy Holdings Pty Ltd J P Morgan Nominees Australia Limited UBS Nominees Pty Ltd Citicorp Nominees Pty Limited HSBC Custody Nominees (Australia) Limited Smartequity EIS Pty Ltd CS Third Nominees Pty Limited Trevor and Judith St Baker Family Philanthropic Pty Ltd Sunset Power Pty ltd St Baker-Childs Investments Pty Ltd Sandhurst Trustees Ltd National Nominees Limited BNP Paribas Nominees Pty Ltd St Baker Sunset Holdings Pty Ltd Sunset Power A Pty Ltd Sunset Power B Pty Ltd Sunset Power C Pty Ltd Sunset Power D Pty Ltd Philip St Baker and Peta St Baker 20 William Mitchell Anderson Total Distribution of shares The following table summarises the distribution of shares as at 22 August 2018: Shareholdings 1 – 1,000 1,001 – 5,000 5,001 - 10,000 10,000 – 100,000 100,001 – and over Total 43,549,489 35,324,382 16,380,196 15,505,639 14,826,684 12,445,148 10,044,848 6,525,242 6,435,892 4,054,228 3,886,092 3,583,381 3,315,768 2,622,185 2,538,749 2,538,749 2,538,749 2,538,749 1,743,368 1,226,331 17.05 13.83 6.41 6.07 5.80 4.87 3.93 2.55 2.52 1.59 1.52 1.40 1.30 1.03 0.99 0.99 0.99 0.99 0.68 0.48 191,623,869 74.99 Number of Shareholders % of issued shares 1,095 2,145 1,027 1,187 101 5,555 0.22 2.47 3.16 11.89 82.26 100.00 The number of investors holding less than a marketable parcel ($500) of 371 shares (based on a market price of $1.350 as at 22 August 2018) was 388, holding 37,949 shares. t r o p e R l a u n n A 8 1 0 2 5 2 1 Share and shareholder information Substantial shareholders The following table shows holdings of five per cent or more of voting rights over Ordinary Shares as notified to the Company under the Corporations Act 2001, Section 671B. Identity of person or group Date notice received Relevant interest in number of securities Percentage of total voting rights Trevor Charles St Baker and St Baker Energy Holdings Pty Ltd 04/07/2016 63,516,907 25.84% Mitsubishi UFJ Financial Group, Inc. Morgan Stanley and its subsidiaries Perpetual Limited and its related bodies corporate 01/06/2018 15,104,294 01/06/2018 15,104,294 14/12/2017 14,460,353 5.89% 5.89% 5.62% Voting rights At a meeting of members, each member who is entitled to attend and vote may attend and vote in person or by proxy, attorney or representative. On a show of hands, every person present who is a member, proxy, attorney or representative shall have one vote and on a poll, every member who is present in person or by proxy, attorney or representative shall have one vote for each share held. Securities Exchange listing The Company’s shares are traded on the Australian Securities Exchange under the symbol “EPW”. Unquoted securities As at 22 August 2018, there were 2,796,793 performance rights on issue under the Company’s employee incentive and retention plans, subject to vesting conditions which once satisfied will, at the election of the Board of ERM Power, convert into: a) b) shares in ERM Power or an offer to apply for an interest in a trust that confers a beneficial interest in ERM Power shares; or a cash payment. Security Description Performance Rights issued 24 Sept 2014 vesting 24 Sept 2019 Performance Rights issued 11 January 2016 vesting 6 January 2019 Performance Rights issued 20 July 2018 with performance period ending 30 June 2020 Performance Rights issued 20 July 2018 with performance period ending 30 June 2021 Performance Rights issued 20 July 2018 with performance period ending 30 June 2022 Total Quantity Number of Holders 280,114 468,232 169,439 1,723,167 155,841 2,796,793 2 2 12 17 2 35 R E W O P M R E 6 2 1 Corporate information ERM Power Limited ABN 22 122 259 223 Directors Tony Bellas (Non-Executive Chair) Albert Goller Georganne Hodges Tony Iannello Philip St Baker Wayne St Baker Jon Stretch (Managing Director and CEO) Company Secretaries Phil Davis Suzanne Irwin Head Office (Registered Office and Principal Place of Business) Level 52, One One One 111 Eagle Street Brisbane QLD 4000 GPO Box 7152 Brisbane QLD 4001 Telephone: (07) 3020 5100 Facsimile: (07) 3220 6110 Auditors PricewaterhouseCoopers Share Registry Link Market Services Limited Level 12, 680 George Street Sydney NSW 2000 Telephone: 1300 554 474 Facsimile: (02) 9287 0303 Internet Address www.ermpower.com.au t r o p e R l a u n n A 8 1 0 2 7 2 1 E R M P O W E R 2 0 1 8 A n n u a l R e p o r t www.ermpower.com.au