We are pleased to present our Draft Plan for the South Australian gas distribution network for the 2021/22 to 2025/26 Access Arrangement (AA) period.
Our Draft Plan sets out very high reliability – one our plan for the next AA hour off supply every 40 period and underpins years on average; and our commitment to offer 1,000 km of mains replaced affordable, safe and since 2016 – future proofing our network. reliable services to our customers. Our Draft Plan outlines how we will continue to deliver on these Australian Gas Networks (AGN) is expectations. It follows more than part of Australian Gas 12 months of engagement with Infrastructure Group (AGIG), one our customers and stakeholders. of Australia’s largest energy Our engagement activities have infrastructure businesses. Our included a series of workshops, South Australian distribution ongoing engagement with our network plays a crucial role in the stakeholder reference groups, and economy and community more co-design workshops. broadly in serving the energy needs of households, small Three key themes have emerged businesses and industry in from this engagement: Adelaide and the regions. not surprisingly affordability Our intention is that customers and price remain the key are at the centre of our plans. issue for the majority of our This will ensure that we deliver for customers; our customers now and into the customers want to ensure future. Our plan seeks to clearly expenditure and investment outline what we have delivered for remain at levels necessary to our customers in the current) AA maintain the safety and period (2016/17 to 2020/21) and reliability of the network; and what we will deliver in the next AA period (2021/22 to 2025/26). the future of gas is a key issue for our customers who In the current AA period we have want to ensure that the demonstrated our commitment to benefits of natural gas delivering on the safety, reliability continue to be available as and service expectations of our South Australia strives customers. In 2018/19 we towards a carbon neutral achieved: economy. our highest ever customer Our Draft Plan delivers on these satisfaction rating 8.4 out of themes. An upfront price cut of 10; and 8% from 1 July 2021 follows on excellent public safety from a 23% cut to our prices five performance – responding to years earlier. Meanwhile our 99% of publicly reported expenditure will maintain the leaks within 2 hours; safety of the network, including through around 860 km of mains replacement.
4 DRAFT PLAN 2021/22-2025/26 CEO FOREWORD
We also outline the initial I strongly encourage our investments that will position the customers and stakeholders to South Australian network for the provide feedback and seek out our future. A recurring theme from engagement activities across our customer and stakeholder South Australia. With your engagement was around emission feedback, we can develop and reductions, and specifically what provide a Final Plan to the we are doing to decarbonise Australian Energy Regulator in energy supply. July 2020 reflective of customer and stakeholder needs now and Further, emission reductions are into the future. increasingly driven by government policy and technology as well as Ben Wilson customer preferences. South Chief Executive Officer, Australia has now proposed to Australian Gas Infrastructure reduce its emissions to 50% of Group 2005 levels by 2030. It is therefore vitally important that gas networks remain at the forefront of this transition. That is why we are presenting proposals to integrate green hydrogen and biogas into our network. We are confident about the future of the network – it represents a significant investment that can deliver safe, reliable and affordable energy with zero emissions in the future. However, the transition underway in the energy sector is not without risks for gas networks – risks over and above those being faced by electricity networks. Yet gas and electricity networks receive effectively the same rate of return. In this light, the prices we propose represent exceptional value for our customers and the South Australian economy. In developing the Draft Plan our objectives are to develop a plan that delivers for current and future customers, is underpinned by effective stakeholder engagement, and is capable of being accepted by our customers and stakeholders. Publishing the Draft Plan is a key part of our no surprises approach. It helps to ensure that customers remain at the centre of our planning.
DRAFT PLAN 2021/22-2025/26 5 CEO FOREWORD
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Our Draft Plan outlines the activities and Plan investments we propose to undertake for the Highlights 2021/22 to 2025/26 period and the resulting price change for our customers.
IN THIS CHAPTER: Our intention is that Our vision is to continue to deliver customers are at the quality services that our We have a strong track customers value, be recognised as centre of our plans. record of safety, reliability a good employer and to remain and customer service in Therefore our Draft Plan sustainably cost efficient. During the current period. has been informed by a the current period we have customer and delivered on that vision, and we An upfront price cut for the stakeholder engagement aim to continue our progress next AA period of 8% during the next AA period. builds on price cuts of program lasting more than 12 months. Our key achievements during the 23% delivered at the current AA period so far are beginning of the current This section highlights how we summarised below. AA period. have developed our Draft Plan, our achievements for the current Delivering for customers period and the key elements of Our customer satisfaction our proposal for the next period. scores have continued to increase, to 8.4 in 2019, our 1.1 Developing this highest score ever. plan Excellent public safety We engaged extensively with a performance – responding to diverse range of customers and 99% of publicly reported stakeholders to understand their leaks within 2 hours. values, needs and expectations of Very high reliability – one the services we provide. hour off supply every 40 Across a series of 14 dedicated years on average. customer workshops spanning five We will have connected over locations and 239 participants, we 30,000 customers this period, listened and informed our Draft bringing our total customer Plan. base to around 450,000. In the development of this Draft 93% of Emergency calls have Plan we have completed stages been answered within 30 one and two of our engagement seconds, with an average program. Further feedback and time to answer calls of 8.4 engagement activities will help to seconds. further refine our Final Plan for submission to the AER in July A good employer 2020. The Total Recordable Injury 1.2 Our track record Frequency Rate (TRIFR) has averaged 10.6 across AGN Over the current period we have since we began tracking this met the high expectations of our metric in 2018. customers and stakeholders, Employee engagement scores including meeting key safety, have remained at or near the reliability and customer service standards set for our business.
10 DRAFT PLAN 2021/22-2025/26 PLAN HIGHLIGHTS
top decile for our industry, the transition to a low carbon significant investment that can averaging 76%. gas supply. deliver safe, reliable and affordable energy with zero 99% of compliance training We will invest $32 million on emissions well into the future. has been completed within projects and programs to the required timeframes. continue to meet the service When these risks are taken into expectations of our account, the prices we propose Sustainably cost efficient customers, including meter represent exceptional value for We will have replaced over replacement, IT and digital our customers and for the South 1,000 km of mains in the services. Australian economy. current period, consistent A good employer with the undertaking we gave to our customers and We will continue to target stakeholders. zero harm throughout our operations. The Adelaide CBD mains replacement is on track for We will maintain top decile completion, which will see all employee engagement scores mains classified as high risk in to ensure we remain the Adelaide CBD replaced by customer and safety the end of the current AA focussed. period. Sustainably cost efficient Opex is expected to be 11% Our combined operating and below our allowance, the capital expenditure will be benefits of which are passed maintained at current levels, onto our customers in our while our network continues proposals for the next period. to grow in size and customer These saving reflect one-off numbers. benefits from our merger with AGIG in 2017. We will make the initial investments that will secure 1.3 What we will the long-term future of the SA deliver distribution network as the state works towards net-zero Our Draft Plan for the next period emissions by 2050. builds on our strong performance over the current period. The Overall, our Draft Plan delivers an activities and expenditure we upfront price cut of 8%, followed propose to undertake in the next by increases of 1.2% per year five years are summarised below. (before inflation) thereafter reflecting the growth in our Delivering for customers regulated asset base. This builds We will connect around on our price cut of 23% delivered 43,000 new residential, at the beginning of the current business and industrial period, and means that by 2025/26 customers. customers will be paying around 20% less (before inflation) than We will replace around what customers paid in 2010/11. 860 km of mains, completing the replacement of the The transition underway in the highest risk mains in our energy sector is not without risks network. for gas networks – risks over and above those being faced by We will respond to clear electricity networks. customer and community expectations to commence We are confident about the future of the network. Our South Australian network represents a
DRAFT PLAN 2021/22-2025/26 11 PLAN HIGHLIGHTS
Purpose of this plan
Regulatory framework After the opportunity to comment on In the last two chapters, we outline the Draft Plan, our customers and how we have calculated the total The National Gas Law (NGL) and stakeholders will also have further revenue required, the resulting National Gas Rules (NGR) provide opportunity to engage as we develop prices for our services (Chapter 13), the framework for the regulation of our Final Plan. The AER will also and the terms and conditions for certain gas pipelines in Australia. engage with stakeholders through its access (Chapter 14). This framework is enacted in South own process. All numbers quoted throughout this Australia through the National Gas Final Plan are dollars of June 2021, (South Australia) Act 2008. How to read this plan unless otherwise labelled. In South Australia, the Australian The first six chapters of this Energy Regulator (AER) is document provide an overview of Next steps our plans, our business, our responsible for regulation under the We encourage our customers and stakeholders, our pipeline services NGL and NGR framework, including stakeholders to provide feedback on and the process we have undertaken the approval of AA proposals and this Draft Plan. Your feedback is a to develop a plan that meets our revisions every five years. key means of achieving our objective vision. The AA contains our proposed of submitting a Final Plan that reference services and the terms and Each subsequent chapter then steps delivers for our customers and is conditions under which a customer through the regulatory building capable of being accepted. blocks that form our required can gain access to the South At the end of each section we have revenue and prices. These are: Australian distribution network. highlighted key questions/issues on This includes: Operating expenditure (opex) – which we are seeking your feedback. the expenditure we require to A full list of the questions posed is the services offered on the run our business day-to-day also provided at the end of this network; (Chapter 7); document.
the price paid for those services; Capital expenditure (capex) – Your feedback can be provided by and the investment in our assets 17 April 2020: required to deliver services to the non-price terms under which online at gasmatters.agig.com.au access will be provided. our customers (Chapter 8); by mail Our review objectives Capital base – the total value of our investment in the South in person Our aim is to develop a plan that: Australian network, which we have not yet recovered from Contact information is provided on delivers for current and future customers and therefore need to the back cover of this document. customers; finance (Chapter 9); is underpinned by effective stakeholder engagement; and Financing costs – the cost of financing our capital base and is capable of being accepted by meeting our tax obligations our customers and stakeholders. (Chapter 10); This Draft Plan seeks feedback on Demand forecasts – the total our plans for the South Australian amount of services we forecast distribution network for the five-year our customers will demand over period commencing 1 July 2021 (the the period (Chapter 11); and next AA period). It will inform our Final Plan, which we are required to Incentive arrangements – submit to the AER by 1 July 2020. additional rewards and penalties that we consider should be The Draft Plan provides our applied to strengthen our preliminary views on the activities efficiency and performance, and expenditure we propose to while promoting the long-term undertake in the next AA period. It interests of our customers includes feedback received to date (Chapter 12). from our customers and stakeholders
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We deliver gas safely and reliably to more Our than 450,000 South Australian homes and business businesses every year.
Australian Gas Networks (AGN) is part of the IN THIS CHAPTER: Australian Gas We are one of Australia’s Infrastructure Group largest gas infrastructure (AGIG), one of the businesses. largest gas Our vision and values drive infrastructure what we do and the way businesses in Australia. we do it. 2.1 About AGIG
AGIG serves over two million customers across every mainland state and the Northern Territory. Our assets include around 34,000km of distribution networks, over 4,000km of transmission pipelines and 57 petajoules of storage capacity. In 2017 AGN, Multinet Gas Networks (MGN) and Dampier to Bunbury (DBP) came together to create AGIG. The scale and expertise of AGIG is delivering enhanced benefits to AGN’s customers in South Australia in the current AA period as outlined in Chapter 3 below.
DRAFT PLAN 2021/22-2025/26 OUR BUSINESS
Figure 2.1: AGIG’s operations across Australia
high levels of reliability and achieve these objectives. The 2.2 Our vision customer service. chapters that follow will discuss our plans in the context of these Our vision is to be the leading gas A good employer – this means objectives alongside the infrastructure business in ensuring the health and requirements of the NGL and Australia. Our definition of leading safety of our employees and NGR. is to achieve top quartile contractors, and having an performance compared to other engaged and skilled We also publicly report under our Australian gas infrastructure workforce. Vision, most recently in our 2018 businesses across all our key Annual Review. targets. Sustainably cost efficient – this means getting the work 2.3 Our values To help achieve this vision, we done within benchmark levels have set ourselves the following by continually looking for Our values of respect, trust, objectives, which we believe are ways to improve cost of perform and one team drive our consistent with being the leading service, pursuing growth, and culture, how we behave and how gas infrastructure business in ensuring we are we make decisions. As the owner Australia. environmentally and socially and operator of critical Delivering for customers – responsible in the way we infrastructure providing essential this means ensuring public provide services. services to Australians, we must ensure we act with integrity and safety and the provision of The activities and investments in do the right thing for current and this Draft Plan are designed to future generations.
DRAFT PLAN 2021/22-2025/26 15 OUR BUSINESS
DRAFT PLAN 2021/22-2025/26 OUR BUSINESS
2.4 Delivering for risk in our operations where we customers first have non-negotiable rules for our staff and contractors to follow. A central element of AGIG’s vision These are essential to keep our is to deliver for our customers. We workforce and the public safe. know that if we do not deliver for They also help us create a strong our customers on safety, safety culture where every reliability, customer service, price employee is personally committed and sustainability they will pursue to managing health and safety. other energy solutions. Figure 2.2: Our Zero Harm Principles Furthering our commitment to put customers at the centre of our business, we are proud to be a founding member of the Energy Charter – giving extra visibility and accountability to this commitment. This commitment reflects our ongoing practice of engaging with customers and stakeholders, including publication of a Draft Plan prior to formal lodgement of our Final Plans with regulators. In developing this Draft Plan, we have engaged with our customers through several activities. This engagement process has enabled customers and other stakeholders to inform and shape our proposals. The outcomes of this process are explained throughout this document, while the stakeholder engagement program is detailed in Chapter 5. 2.5 Zero Harm
Maintaining the safety of our workforce and the public is always front and centre in all our activities. When developing our Final Plan and the work programs that underpin it, our aim is to do everything we can to meet the obligations of our safety case and asset management strategies. We are continually striving to achieve Zero Harm and have comprehensive health and safety policies, procedures and training that support the delivery of this ambition. Our Zero Harm Principles (shown in Figure 2.2) highlight areas of
DRAFT PLAN 2021/22-2025/26 17 OUR BUSINESS
2.6 The gas supply More information on HyP SA and chain our low carbon journey is available in Boxes 2.1 (page 22) AGIG owns and operates gas and 4.1 (page 32). infrastructure, including transmission pipelines, distribution networks and gas storage facilities across Australia. Our assets play an important role in the safe and reliable supply of gas to customers at various parts of the gas supply chain. Key components of the gas supply chain include upstream production and processing, transmission, distribution, storage and downstream consumption. Our customers purchase gas from retailers, which is delivered directly to them by our South Australian distribution network. 2.7 Our role in South Australia
Natural gas plays a pivotal role in South Australia providing a reliable source of energy for homes, businesses and power generation. Gas represents almost 40% of the total energy consumption in the state. Figure 2.3 shows the location and key features of our South Australian distribution network. The network is more than 8,100 km long, serving residential, commercial and industrial business customers in Adelaide (from Two Wells to Aldinga) and regional centres in the Upper North, Barossa, Riverland and South East of the state. AGIG is also at the forefront of the emerging hydrogen industry in Australia through our investment in Hydrogen Park South Australia (HyP SA). HyP SA is a key part of our vision to be environmentally and socially responsible, by developing and implementing a pathway to zero emissions for our South Australian distribution network.
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DRAFT PLAN 2021/22-2025/26 19 OUR BUSINESS
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Box 2.1: Planning for our low carbon future Our network is on the pathway to a cleaner energy future. We will achieve this by using renewable or carbon neutral gas, such as hydrogen and biomethane.
The energy sector is rapidly changing Since the beginning of the current AA period, there has been significant change in the energy sector with global, national and state level commitments to reducing emissions rapidly. To protect our climate, environment and the prosperity of future generations, there is a growing recognition that cleaner energy sources with zero or net zero emissions need to replace existing sources from fossil fuels by 2050. More importantly, governments, businesses and customers are rapidly shifting to cleaner forms of energy in response. The Paris Agreement sets the goal for action across the globe, including in Australia, to limit global temperature increases to well below 2oC and preferably limiting the increase to 1.5oC.
In Australia a number of policies are of particular importance in achieving this goal. In particular: the Commonwealth has committed to reducing emissions by 26-28% below 2000 levels by 2030; and the South Australian Government is working towards net zero emissions by 2050, and has recently adopted a target of 50% below 2005 emissions by 2030. The force of the transition underway is particularly evident in the increasing uptake of renewable electricity – reaching 51% of the electricity produced in South Australia in 2018. While the transition to cleaner forms of energy is underway, it is clear more needs to be done, and we need to play our part. To achieve net zero emissions will require a shift in all energy use, not just electricity. And it is clear that gas is essential to our economy and modern lifestyles. Figure 2.3 shows that renewable electricity and electricity overall represents only a small portion of our total energy use. Gas and transport fuels provide a significant portion of total energy consumption. We recognise that if South Australia is to meet its emission reduction targets we need to focus on large-scale decarbonisation of the entire energy supply chain, including gas delivered by our South Australian distribution network. We need options beyond electricity if customers are to receive clean and reliable energy at the lowest possible cost.
Figure 2.3: South Australia’s daily energy consumption 2015/16 – 2017/18
To achieve net zero emissions will require a shift in all energy use, not just electricity. And it is clear that gas is essential to our economy and modern lifestyles.
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Customers like the benefits of gas and want it to continue to play a role in achieving net zero emissions
Our customers like gas and the benefits it brings – comfort, convenience and reliability. As a result, the number of gas connections on our South Australian network continues to grow – from 442,000 in 2016/17 to 454,000 in 2018/19. In our stakeholder engagement program it has been clear that customers recognise the need to reduce emissions. Customers expect AGN to find solutions that maintain the benefits of gas and also reduce emissions. “Climate change needs to be addressed by all businesses but most importantly by a large network.” Customer, Phase 2 Workshop Gas networks will be part of the solution by using carbon-free or carbon-neutral gases such as hydrogen and biomethane in place of natural gas. These two renewable gases are described in more detail below.
Gas, the Natural Choice for the Future While natural gas has lower emissions than electricity from fossil fuels, for our gas distribution network to be part of the long-term transition to zero emissions, we need to develop and invest in alternative fuels. In particular, we are focussing our efforts on hydrogen and biomethane. From natural gas, to biomethane to hydrogen, it is clear that there is a role for gas in the future. It is reliable, customers like using it and it will become the lowest cost option to achieve emissions reductions. The cost of producing hydrogen through electrolysis is declining rapidly as noted in the CSIRO National Hydrogen Roadmap. At a project level costs are falling even faster than expected by CSIRO. Based on these reductions research by Deloitte and used as part of the Hydrogen Strategy Group’s report to the Council of Australian Governments, suggests using hydrogen to replace existing uses of natural gas is 40% cheaper than electrifying these same uses of energy. Renewable gases like hydrogen and biomethane maintain the benefits for customers of natural gas with none of the emissions that contribute to climate change. Renewable gases can also be used to lower emissions from other sectors like transport, industry and electricity generation. The National Hydrogen Strategy, which was released in December 2019, recognised the enormous potential of hydrogen for domestic use and export.
“Our vision is a future in which hydrogen provides economic benefits to Australia through export revenue and new industries and jobs, supports the transition to low emissions energy across electricity, heating, transport and industry, improves energy system resilience and increases consumer choice.” Dr Alan Finkel, Australia’s Chief Scientist South Australia has great potential to harness the benefits of a hydrogen economy. The State’s renewable electricity resources, expertise in energy export and gas infrastructure position us well to decarbonise our own systems as well as global markets. Importantly a new hydrogen economy will translate to new jobs and growth.
“Hydrogen offers an opportunity to ensure that the transition to cleaner energy is affordable and reliable for South Australian consumers. Once produced using renewable energy, hydrogen can be blended into gas networks, used in transport, or reconverted back to grid electricity when needed.” South Australian Hydrogen Action Plan, Government of South Australia, September 2019.
Hydrogen can be used much like natural gas to heat homes, Biomethane is the net-zero emission gaseous fuel power vehicles and produce electricity, but importantly when recovered from a wide range of renewable sources, burned it produces only water vapour and energy as heat, such as wastewater, food waste and landfill. Because with no carbon emissions. If produced from water using the gas is recovered from other sources (preventing it electrolysis powered by renewable electricity hydrogen is zero from entering the atmosphere), it can be a source of emissions. Blended with natural gas, hydrogen is likely to net zero emissions. More importantly, biomethane require no need for modification to existing appliances or the can be produced to have much the same composition network. However, higher volumes will require some as natural gas today, meaning it can be injected into modification to account for the different characteristics of our networks with no modification to the network or hydrogen and methane. user appliances.
DRAFT PLAN 2021/22-2025/26 23 OUR BUSINESS
In the 2016/17 to 2020/21 period we have Our track continued to deliver the strong safety, record reliability and service standards expected by our customers.
IN THIS CHAPTER: Our focus in the current 93% of Emergency calls have period has been on been answered within 30 In 2019 we achieved our maintaining the safety seconds, with an average highest ever customer time to answer of 8.4 and reliability of the satisfaction score of 8.4. seconds; and network, improving our customer satisfaction scores We will connect over responsiveness to 30,000 customers this have continued to increase, to customer needs, and period, bringing our total 8.4 in 2019, our highest score customer base to around reducing costs. ever. 450,000. In accordance with our vision, our 3.2 A good employer aim is to be the leading gas We have completed or are infrastructure business in Australia To be a good employer we focus on track to complete major by achieving top quartile on the health, safety, projects including the performance on all of our key engagement, skills and training of Adelaide CBD mains targets. our workforce. In the current replacement. period to date: Our activities throughout the current period have been guided the TRIFR has averaged 10.6 by our key objectives of delivering across AGN since we began for customers, being a good tracking this metric in 2018; employer and remaining we have introduced a number sustainably cost efficient. Figure of health and safety initiatives 3.1 below summarises our including annual zero harm performance in the current period workshops, a HSE culture to date against our vision. model and reporting, and HSE Overall, we have met the key recognition awards; safety standards set for the employee engagement scores business and delivered the major have remained at or near the outputs set by the AER. top decile for our industry, 3.1 Delivering for averaging 76%; and customers 99% of compliance training has been completed within We deliver for customers by the required timeframes. maintaining public safety, reliability and customer service standards. In the current period to date:
excellent public safety performance – responding to 99% of publicly reported leaks within 2 hours;
very high reliability – one hour off supply every 40 years on average;
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Figure 3.1: Our performance against our vision in current period (2016/17 to date, with forecast performance to the end of the period where applicable)
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3.4 Sustainably cost efficient
To be sustainably cost efficient we focus on working within industry benchmarks, delivering profitable growth and being environmentally and socially responsible. In the current period:
we will deliver over 1,000 km of replacement of our aging mains, consistent with that expected for this period;
Adelaide CBD mains replacement is on track for completion, which will see all mains classified as high risk replaced by the end of the current AA period; opex is expected to be 11% below our allowance, the benefits of which are passed onto customers in our proposals for 2021/22- 2025/26; and $12 million was invested to upgrade the Southern metro network and to connect McLaren Vale and other new developments.
26 DRAFT PLAN 2021/22-2025/26 OUR TRACK RECORD
27 DRAFT PLAN 2021/22-2025/26 WHAT WE WILL DELIVER
This Draft Plan reflects our vision to be the What we leading gas infrastructure business in will deliver Australia, continuing to deliver on the priorities of our customers – affordable, safe and reliable services now and into the future. IN THIS CHAPTER: We will continue to deliver Customers have been at meters, to connect around for customers in the next the centre of our 43,000 new residential, AA period connecting business and industrial planning for the next AA customers; around 43,000 new period. Based on their replacing a further 860 km of customers. feedback we continue to old cast iron, unprotected We will replace around focus on providing high steel and first-generation 860 km of mains, levels of community plastic pipes. We will replace completing the safety, network all of our old cast iron mains replacement of the highest reliability and customer by the end of the next period, risk mains in our network. which is a significant safety service, at an affordable milestone; An upfront price cut of 8% price. builds on price cuts of responding to customer and Our Draft Plan presents further community expectations to 23% delivered at the reductions in our prices by commence the transition to a beginning of the current investing efficiently in our assets low carbon gas supply; period. and operations. Highlights of what $32 million on projects and we will deliver are included in By 2025/26, customers programs to continue to meet Figure 3.1 and described in more will be paying nearly 20% the service expectations of detail in the sections that follow. less (before inflation) than our customers, including: what customers paid in 4.1 Delivering for our meter replacement 2010/11. customers program ($19 million);
Delivering for our customers investment in our IT means ensuring public safety and systems that support our high levels of reliability and customer service functions customer service. ($8 million); Our customers expect that we providing more digital maintain the safety and reliability services and a greater of the network. In the next period variety of communication we will deliver for customers by: channels ($5 million).
responding to public leak reports within 2 hours more than 95% of the time and repair leaks within the timeframes set by our Leak Management Plan 100% of the time; deliver customer satisfaction scores at or above 8.2;
laying reticulation mains and services, and installing
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Figure 4.1: Our performance targets for the 2021/22 – 2025/26 period
DRAFT PLAN 2021/22-2025/26 29 WHAT WE WILL DELIVER
4.2 A good employer state works towards net-zero emissions by 2050 such as: Being a good employer means proposing to customers prioritising the health and safety that we offset a portion of of our employees, focussing on our unaccounted for gas employee engagement and skills (UAFG) with biomethane, development. which is a net carbon Investing in our workforce helps neutral gas; ensure we can continue to deliver proposing to customers a services that meet our customers’ South Australian Green Gas expectations. Community Education In the next period we will be a Centre at the Tonsley good employer by: Innovation District; and
continuing to target zero considering the harm through workshops and introduction of a network embedding our HSE culture innovation scheme, which model; could support the decarbonisation of our gas continuing ongoing health and supplies and the move to safety initiatives, including our smarter gas networks. various wellbeing initiatives;
maintaining top decile employee engagement scores to ensure we remain customer and safety focussed. 4.3 Sustainably cost efficient
Being sustainably cost efficient means working within industry benchmarks, delivering profitable growth and being environmentally and socially responsible. In the next period we will be sustainably cost efficient by:
delivering an upfront price cut of 8% on 1 July 2021, which builds on price cuts delivered by our business in the current period; maintaining combined operating and capital expenditure at current levels, despite our network growing in size and customer numbers;
taking the first steps to help secure the long-term future of the South Australian distribution network as the
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DRAFT PLAN 2021/22-2025/26 31 WHAT WE WILL DELIVER
Box 4.1: Playing our part in the decarbonisation journey AGIG is investing to develop and demonstrate renewable gases across our operations. We are focused on using our expertise in infrastructure development and operation and our experience with customers across Australia, to deliver this green gas future.
Hydrogen Park South Australia
In South Australia, we are kick-starting the hydrogen economy. From mid-2020, we will produce renewable hydrogen using water and renewable electricity through a process known as electrolysis. Hydrogen will be blended with natural gas and supplied to more than 700 residential and business customers in Mitchell Park, South Australia, an Australian first. Over 2019 we made significant progress with this project. We engaged Valmec and GPA Engineering to design and construct the project; introduced the project to the community; had our Development Application approved; completed construction of our hydrogen storage vessel and along with the Premier of South Australia and South Australian Minister for Energy and Mining, broke ground onsite. We are not only focused on delivering Hydrogen Park South Australia (HyP SA) but also on expanding its operations. Planning is underway for tube and trailer facilities to transport by truck the hydrogen to industry and add motor vehicle refuelling stations across the state.
Figure 4.2: Artist impression of Hydrogen Park South Australia
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The Australian Hydrogen Centre
We are establishing the Australian Hydrogen Centre (AHC), with a range of public and private sector partners. The AHC will help advance the renewable hydrogen industry by developing feasibility studies to inject up to 10% renewable hydrogen into regional and metropolitan gas distribution networks in South Australia and Victoria. It will also develop a pathway to make the transition to 100% hydrogen networks. In addition, the AHC will publish knowledge sharing reports to share key insights and data from the operations of HyP SA. Founding members of the AHC include the Government of South Australia’s Department for Energy and Mining and Victoria’s Department of Environment, Land, Water and Planning, AusNet Services, Engie and Neoen Australia.
Renewable gas in the next AA period Gas is an essential part of our economy and of our customer’s daily lives. We understand that our customers value the reliability and instantaneous nature of gas heating. However, affordability and a cleaner future are also key considerations. Figure 4.3: Cooking on our hydrogen barbeque With this in mind we have been leading industry in developing the renewable gas industry. Over the current period we have been active contributors to the National Hydrogen Strategy and South Australia’s Hydrogen Action Plan, whilst developing the Australian-first HyP SA project and the AHC. We are participating in further research through the Future Fuels Cooperative Research Centre, and importantly we are continually engaging with our customers and stakeholders to ensure that our work continues to deliver for their future. Whilst significant progress has been made during the current period, we can do more, and our customers have asked us to consider what more we could do to deliver this clean energy future.
In this Draft Plan we are considering a range of additional initiatives that will ensure the South Australian distribution network is ready for the transition to zero emissions. More information on these initiatives can be found in the following chapters:
Greening UAFG by substituting natural gas with hydrogen or biomethane (Chapter 7). Establishing a Community Education Centre (Chapter 7). Establishing an innovation allowance, allowing us to access funds for renewable energy and other innovative projects when they arise (Chapter 11). We look forward to receiving feedback on these initiatives.
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We engaged extensively with our Customer customers and stakeholders to inform and and shape this Draft Plan. Our approach puts Stakeholder customers at the centre of our planning to Engagement ensure that we continue to deliver valued services for South Australians, now and in the future. IN THIS CHAPTER: We engaged extensively our plans. We engaged with our with a diverse range of 5.1 Overview customers and customers and Our objective is to develop a Final stakeholders to stakeholders to Plan which delivers for current understand how they understand values, and future customers, is wanted to be involved in needs and expectations underpinned by effective the development of our of the services we stakeholder engagement and is plans. provide. capable of being accepted by our customers and stakeholders. We held iterative Our Draft Plan outlines workshops with customers We adopted a four staged how we have responded across South Australia to approach to our engagement understand customer to this feedback, and program which illustrated in Figure 5.1. We use this framework needs and preferences. provides another opportunity for to report the outcomes against We worked closely with our engagement activities. customer feedback on stakeholders in reference our overall plans. In the development of this Draft group meetings, one on Plan we have completed stages one meetings and This chapter explains our one and two of our engagement interactive workshops. customer and stakeholder program. engagement program, activities
we have undertaken, feedback we received, and how this feedback has influenced
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Figure 5.1: Our Four Stage Approach to Engagement
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Stage 1: Strategy & Research
In Stage 1 we consulted on our draft engagement strategy. We believe this a critical step in the process as it ensures our engagement program is fit for purpose, meets the needs of our customers stakeholders and identifies key topics for consultation early in the process. We published our Draft Customer and Stakeholder Engagement Plan for consultation in April 2019.
We invited stakeholders to provide to support the development of our our pipeline services; feedback on the most important Draft Plan, including:- aspects of our service and issues customer experience and we should be considering in our Regular South Australian flexible solutions; Reference Group (SARG) future planning. This enabled us our price structure; to focus on these topics in Meetings; subsequent engagement activities Regular Retailer Reference our capex and opex in Stage 2. Group (RRG) Meetings; proposals; In Stage 1 stakeholders identified Customer workshops (two demand forecast; iterative phases to date); the following key topics as issues rate of return; of importance for consideration in A major customer survey; incentives; the development of our plans: Co-design workshops with Price and affordability; stakeholders; and setting our capital base; and Online engagement on Gas Future of gas and future of gas Matters. decarbonisation; and A full list of engagement topics Stage 2: Stakeholder Reference Our capital works program. discussed at meetings is shown in Groups Tables 5.3 and 5.4. A summary of all customer and Membership of our South stakeholder feedback from Stage Stage 2: Customer Engagement Australian Reference Group 1 and how we responded is shown (SARG) reflects the diversity of Engaging directly with customers in Table 5.1. our customer base, with in the development of this plan is In July 2019 we published our organisations representing a critical component of Stage 2 to Stage 1 Customer and residential customers, vulnerable ensure we align our plans and Stakeholder Engagement Report, customers, older Australians, proposals with customer needs which summarised key insights multicultural communities, and expectations. from our early engagement and business and industrial customers, Our customer engagement documented our final engagement builders and developers, and local workshops are run in three phases plan. government. with the same groups of The Retailer Reference Group customers, allowing iterative Stage 2: Developing (RRG) comprises representatives engagement as our plans are our Draft Plan from gas retailers who operate in developed. national markets which we serve, To date we have completed two In Stage 2 we delivered a range including South Australia. phases of workshops in the of engagement activities with our Through regular meetings (10 in development of this Draft Plan. key stakeholders and customers Stage 2) we consulted with key stakeholders on topics including:
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Repeat engagement with the same groups of customers enables us to:
Build customer knowledge over time to allow customers to make informed decisions Listen, test and validate our ideas in response to customer feedback as we develop our proposals Prioritise and explore issues in more detail in response to customer feedback
Two phases of workshops were held in 5 locations across South importance further and tested to reduce carbon emissions Australia with a total of 239 costed proposals for feedback. (for further consultation with participants across 14 workshops. High level findings from the customers) We held dedicated workshops for customer workshops are Customers support residential, business, summarised as follows: investment in innovation metropolitan, regional and Price and affordability is the projects culturally and linguistically diverse most important issue for More detail about the information (CALD) customers. customers we presented at customer Customer workshops were Customers value current workshops, the questions we facilitated by an independent third levels of reliability and public asked and their feedback is party (KPMG) to provide safety and support AGN’s outlined in Section 5.4 of this independence in how customer proposal to maintain these chapter. service levels feedback was captured and Stage 2: Major User Survey documented. Customers expect AGN to deliver more customer As part of Stage 2 engagement In Phase 1 and 2 workshops we services via digital channels, activities we also engaged with covered the following topics with our large industrial customers and Customers consider customers: sought insights into future sustainability and demand through a survey and a Reliability of service; decarbonisation as very series of one-on-one meetings. Public safety; important and want AGN to consider more opportunities Customer service; Network growth; Sustainability; and Innovation. The first phase of workshops were designed to understand customer values, needs and service expectations. We also provided information for customers about our business, our role in the gas supply chain, and how we develop our business plans. In the second phase of customer workshops we validated customer feedback, explored issues of
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Stage 2: Co-design Workshops How have our To support stage 3 engagement with Stakeholders we are: engagement activities We are committed to delivering Publishing our Draft Plan for all customers, including influenced and shaped online for a 2 month period for ensuring our services are our plans? public consultation accessible to those who are most Engaging with customers in vulnerable in our community. All feedback from regular South our third phase of workshops Australian Reference Group As part of our Stage 2 meetings, Retailer Reference Continuing our meetings with engagement activities we also Groups, together with feedback SARG and RRG included a series of three co- from meetings with stakeholders, design workshops with Briefings and one on one customer workshops and stakeholders on the topic: How meetings with stakeholders government agencies has been might AGN better support captured and used to shape and These activities support engaging vulnerable customers – now and refine our Draft Plan. on the details of our plans, in the future? including in the context of our A summary of feedback and how Co-design is a process by which broader business plans. it has informed our Draft Plan is organisations collaborate with included in Table 5.7. stakeholders and customers to inform decision making. Each chapter of this Draft Plan also includes a section on Workshop participants were customer and stakeholder experts from the social and engagement. community services sector including financial hardship, disability, mental health, culturally Stage 3: Consultation and linguistically diverse (CALD) on this Draft Plan people, and older Australians. We are now in Stage 3 of our four Feedback from the workshops and staged approach (February – how we plan to respond is March 2020) and are consulting addressed in section 5.4 of this widely with customers and chapter. stakeholders on this Draft Plan.
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Figure 5.2: Our stakeholders 5.2 Our Stakeholders
We have identified a number of stakeholder groups with an interest in how we plan, manage and operate our gas distribution network. In Stage 1 we consulted with key stakeholders and sought feedback to ensure we captured all relevant stakeholders. Our South Australian Reference Group and our Retailer Reference Group represent a cross-section of our customers, energy retailers, government agencies and other businesses in the gas supply chain. Our key stakeholder groups are illustrated in Figure 5.2. 5.3 Stage 1: Strategy & Research The aim of Stage 1 was to better understand customer and During stakeholder meetings we potential opportunities for stakeholder needs and facilitated discussion around three renewable gas and including expectations. It included consultation questions: hydrogen blended into the gas consultation on our proposed distribution network. engagement strategy. What are the most important aspects of our services? Stakeholders place value on This is an important step in our reliability and maintenance of four staged approach to ensure What issues should we be current service levels and noted we were engaging with the considering in our future that for many customers gas is a relevant key stakeholders and planning for the pipeline? critical input into their business they were comfortable with What aspects of our future operations. proposed engagement activities. plans would you like to Other topics of interest included We sought to understand what is engage on? our capital program and important to our customers and As shown in Figure 5.4, the key opportunities to raise community stakeholders – and what topics areas of interest were price, awareness of the gas supply they wanted to be engaged on. future of gas and our capital chain. As part of Stage 1 engagement works program. We also sought feedback on our we consulted on our Engagement Stakeholders told us that the cost proposed engagement strategy, Principles as shown in Table 5.2 of utilities (broadly) and including our proposed approach overleaf. These principles were affordability are important issues to stakeholder engagement, endorsed by all stakeholders. for business and residential identification of key stakeholders, In May 2019, we held one-on-one customers and that they sought proposed engagement activities consultation meetings with 15 price certainty. and the timeline. South Australian Reference Group Many stakeholders noted the rapid Feedback from stakeholders was members and 2 government changes taking place in the used to inform our final agencies to discuss our proposed energy industry, and are engagement strategy – ensuring approach and explore key issues. interested in the future of gas and
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our activities were appropriate Table 5.2: Our Customer and Stakeholder Engagement Principles and allowed for meaningful engagement. Principle Our Commitment Upon concluding Stage 1 we released a report summarising Genuine and We listen and respond to the needs of our customer and stakeholder Committed customers and stakeholders, driving a culture of delivering value for our customers. feedback, and our final engagement strategy. Clear, accurate We provide information that is clear, accurate, A copy of our Stage 1 Stakeholder and timely relevant and timely Engagement Report is available communication on Gas Matters
(gasmatters.agig.com.au) A summary table of all feedback Accessible and We involve customers and stakeholders on an Inclusive ongoing basis in a meaningful way to ensure that and how we responded in Stage 1 our plans deliver for our customers. is illustrated in Table 5.1.
Transparent We clearly identify and explain the role of customers and stakeholders in the engagement process, and consult with customers and stakeholders on information and feedback processes.
Measurable We measure success, or otherwise, of our engagement practices to ensure ongoing improvement
Figure 5.3: Stage 1 Key topics of interest for stakeholders
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Table 5.1: Stage 1 Customer and stakeholder feedback summary
Topic Customer and stakeholder feedback Our response
Our Stakeholders noted Stage 1 engagement activities were important to We have confirmed our engagement clearly define our customers and stakeholders, the broad areas for four stage approach to approach and engagement and timing. develop our Final Plan. Stakeholders supported the Energy Charter, our principles of We have confirmed our principles engagement, our ‘no surprises’ approach and our focus on our commitment to our customers. engagement principles and Reference Group Members mentioned the high quality of meeting ‘no surprises’ approach. materials and presenters. The information was well structured and We will ensure a strong the objectives clear. customer focus, including Stakeholders supported our staged approach to developing our plans, clearly explaining how our particularly the release of and engagement on our Draft Plan. plans are in the long-term Transparency and accessibility was highlighted by stakeholders as interests of our customers. critical as we develop our plans. We will continue to engage Reference Group Members were keen to ensure the objectives of with our stakeholders and each meeting were clear and there was clarity on meeting agenda SA Reference Group items. members on key issues as Reference Group Members may consider opportunities to co-share part of our business as responsibilities and attendance at meetings depending on agenda usual activities. items. Stakeholders indicated they would like to maintain a working relationship with AGN post the engagement around future planning. Our Stakeholders were of the view the Reference Group comprises We will consider stakeholders a broad spread and cross-section of the community. opportunities to engage Stakeholders noted environmental representation should be environmental considered. representation. Stakeholders were positive that senior levels of AGN staff were We have revised our present at the meetings. stakeholder map. Stakeholders expressed interest that the stakeholder map identified The Terms of Reference the broader community as a stakeholder. have been amended. Stakeholders would like the stakeholder map in the Terms of Reference to be amended to correctly identify their membership. Our In relation to SA Reference Group meetings, stakeholders suggested We have committed to that: issuing meeting agendas engagement • meeting objectives are clear and agendas sent promptly and materials in a timely activities • consideration be given to having separate business and residential way meetings (for specific issues) Where appropriate, we will • there could be benefit in members meeting together with the facilitate separate Retailer Reference Group Reference Group sessions Reference Group Members are of the view the quality of meeting for residential and business materials is satisfactory customers Reference Group Members may look to co-share meeting We will invite retailers to responsibilities depending on agenda items meet with South Australian All stakeholders supported engagement with customers as part of the Reference Group members suite of engagement activities where appropriate Stakeholders were keen to ensure that customer engagement We are documenting and activities such as workshops or forums were representative of the reporting on our customer community (e.g. CALD community, people with disabilities, Older engagement activities Australians) We will seek ongoing SA and Retailer Reference Group members supported the advice from Reference ongoing Reference Group meetings as an efficient way to Group Members on receive input into the development of our plans ensuring representation of Stakeholders value regular one-on-one meetings to discuss the community, and the specific issues in detail development of materials Stakeholders indicated they would like to be kept informed of We will provide our progress and plans regular updates via a Digital updates and factsheets were considered an efficient way range of platforms to to keep stakeholders informed keep stakeholders Some stakeholders expressed interest in working closely with informed AGN on identifying issues of importance and co-designing solutions We are scheduling reference group meetings aligned to developing our plans. Our timeline Customers and stakeholders supported our timeline. We have confirmed the timeline for developing our plans.
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5.4 Stage 2: Developing our Draft Plan
In Stage 2 we delivered a series of engagement activities to inform the development of this Draft Plan, namely regular SARG and RRG meetings, two phases of iterative customer workshops, and a dedicated co-design workshop with stakeholders. Our Stakeholder Reference Groups
We engaged with our Stakeholder Reference Groups as a key way to receive input on our plans as they have been developed.
Six meetings of the South A summary of key topics and part of our ‘no surprises’ approach Australian Reference Group information presented is to engagement. (SARG), and four meetings of the summarised in Tables 5.3 and 5.4. Retailer Reference Group (RRG) Feedback from our Stakeholder were held between April and Both Groups were keen to Reference Groups, and how we December 2019. understand our future plans in the have responded in this Draft Plan, context of price, and importantly is included in Table 5.7. Meeting topics and materials were that our proposals are cost presented based on issues of efficient whilst delivering value for importance to stakeholders raised customers. in Stage 1, and key components of this Draft Plan. We provided early price modelling to members at our meetings in
August and December 2019 as
Stakeholder Reference Group Membership
South Australian Stakeholder Reference Group Australian Industry Group (SA) South Australian Council of Social Service Multicultural Communities Council of SA Financial Counsellors of South Australia Urban Development Industry Australia (SA) Property Council of Australia (SA) Federation of Residents and Ratepayers Association Inc Business SA Consumers SA Council for the Ageing (SA) Local Government Association (SA) Retailer Reference Group: Our retailer reference groups includes representatives from the major retailers including AGL, Lumo/ Red Energy, Alinta Energy, Energy Australia, Origin Energy, Savant Energy Power, Simply Energy
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Table 5.3: South Australian Reference Group (SARG) Meetings
MeetingFigure 5.6# : SouthKey TopicsAustralian Reference Group (SARG)Summary Meetings of Information presented
Meeting #1 Our business and our Our vision and values Developing our future plans Role of the SA Reference Group and introduction (April 2019) Our draft engagement plan Overview of the regulatory framework Reference services Our stakeholder engagement approach Overview of proposed reference services Meeting #2 Final engagement plan Stakeholder insights/feedback from our engagement Developing our future plans Our pipeline and reference services proposal (June 2019) Pipeline and reference services Meeting #3 Stage 1 Engagement Report Customer growth and satisfaction results Our capex proposal Our Stage 1 Stakeholder Engagement Report (August 2019) Future of gas and hydrogen Overview of Phase 1 customer workshops and co-design Pipeline and reference services Capital works program, operating context and approach Future vision for gas networks and innovation Submission of the Reference Services Proposal Meeting #4 Early price modelling Early price modelling Phase 1 customer workshops Results from Phase 1 customer workshops (August 2019) Regulatory building blocks Building blocks overview – how prices are determined
Meeting #5 Updated price modelling Our Energy Charter Disclosure Report Phase 2 customer workshops Early price forecast (October Co-design: Vulnerable Customers Approach to Phase 2 customer workshops 2019) Capex and opex proposals Our online engagement portal, Gas Matters Our co-design process supporting vulnerable customers Our preliminary expenditure proposals Meeting #6 Rate of Return Updated price forecast Capital Base Observations from our co-design process (December Incentives Results of our Phase 2 workshops 2019) Demand Regulatory modelling update
FigureTable 5.4: 5.6 Retailer: South Reference Australian Group Reference (SARG) Group Meetings (SARG) Meetings
Meeting # Key Topics Summary of Information presented
Meeting #1 Our business Our vision and values Developing our future ps Role of the Reference Group and issues of importance (April 2019) Our draft engagement plan Overview of the regulatory framework Reference services Our stakeholder engagement approach Terms and conditions Overview of proposed reference services Our approach and timeframes for terms and conditions Meeting #2 Final engagement plan Stakeholder insights/feedback from our engagement Developing our future plans Future of Gas and hydrogen (July 2019) Pipeline and reference services Our pipeline and reference services proposal Draft terms and conditions An overview of the draft terms and conditions
Meeting #3 Capex and opex proposals Our Stage 1 Stakeholder Engagement Report Pipeline and reference services Overview of Phase 1 customer workshops and co-design (Nov 2019) Draft terms and conditions Capital works program, operating context and approach Future vision for gas networks and innovation Submission of the Reference Services Proposal Feedback on draft terms and conditions Meeting #4 Phase 2 Customer workshops Early price modelling Regulatory building blocks overview Results from Phase 1 customer workshops (Dec 2019) Rate of return Pricing - Regulatory Building blocks overview Demand forecast Feedback on current draft terms and conditions Draft terms and conditions
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Customer Workshops; Recruitment and participation Table 5.5: Phase 1 & 2 Workshop Attendance
We engaged with a diverse group Location Customer Phase 1 Phase 2 Return of customers through a series of Segment Workshop Workshop Rate iterative workshops to inform and Attendance Attendance (%) shape this Draft Plan. Adelaide Our customer engagement Residential 20 15 75 workshops are run in three phases customers with the same groups of Adelaide Business 19 17 89 customers, allowing iterative customers engagement as our plans are Adelaide developed. CALD 21 16 76 customers We have completed two phases of workshops in the development of Port Pirie Residential 16 14 88 this Draft Plan, with a third phase and business of workshops to be held as part of customers Draft Plan consultation. Barossa Residential 17 11 65 Two phases of workshops were and business held in 5 locations across South customers Australia with a total of 239 Murray CALD 10 6 60 participants across 14 workshops. Bridge customers Customer attendance at each Mt Gambier workshop is shown in Table 5.5. Residential 25 22 88 and business We held dedicated workshops for customers residential, business, metropolitan, regional and TOTAL 128 101 77 culturally and linguistically diverse (CALD) customers. invited community leaders as Phase 1 Customer Workshops: Participants were recruited participants from cultural groups Objectives, engagement activities through a specialist third party including Bhutanese, Chinese, and results provider and represented a broad Eritrean, Fijian, Filiapino, Fullah, The objectives of Phase 1 cross section of the community. Indian, Ivorian, Serbian, Sierra customers workshops were to:- Leone, Somalian and Spanish. We partnered with the Understand customer values, Traditional Aboriginal land owners Multicultural Communities Council service expectations and of South Australia (MCCSA) to were also represented at the priorities to inform future hold workshops with customers workshops held in Murray Bridge. investment plans from CALD communities. MCCSA
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Engage with, and listen to While the current price of gas customers to understand does not appear to be of major issues of importance concern, price and affordability is Educate customers about the top priority for customers in AGN and its role, to facilitate managing utility bills for their ongoing engagement at homes and businesses. phase 2 and 3 workshops “With a young family, my Phase 1 workshops were 90 minutes in duration with first priority is always participants working in groups at affordability” tables. AGN presenters and subject matter experts were Customers told us they highly available to respond to questions. value an uninterrupted supply of gas in their homes and business We asked customers a series of and are satisfied with current questions relating to reliability, levels of reliability. public safety, customer service, Customers told us it was affordability, the gas network and sustainability. important to receive timely customer service by Sustainability was a key area of Key topics, information presented knowledgeable staff who interest for customers. Customers and insights from Phase 1 are demonstrate empathy and were more aware of opportunities illustrated in Figure 5.6. understanding in responding to to lower carbon emissions from In Phase 1 Customers told us that queries or resolving issues. electricity and were very keen to understand innovation in gas and their top priorities are price/ In terms of customer service, how AGN could play a role in affordability, reliability of supply, customers were satisfied with decarbonisation. maintaining public safety, and the current service levels, with future of gas in a low carbon preferences for interacting with economy. AGN through a variety of channels (e.g. website, email, web chat).
Engaging with customers in the context of price and how this impacts customer bills
As part of engaging with customers to develop our Draft Plan we have provided customers with information about how prices are set. We have been clear where feedback or decisions they make may have a bill impact. Some of the ways we have done this include:- Price setting information presented at all customer workshops, including the regulatory building blocks Price setting information about how gas bills are made up, including the split between other costs in the supply chain Fact sheets provided to all customers “Understanding your gas Bill” A short video “Understanding how prices are set” available at sessions and online Open discussion forum on prices and how they are set at all customer workshops Presenting proposals with transparency around expenditure levels Providing an indication of bill impact where customers are invited to provide feedback/ and or indicate whether they support proposals
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“Reliability is critical…. public safety is assumed…need to innovate and reduce carbon footprint”
A full report on the Phase 1 Workshops and results is available on Gas Matters (gasmatters.agig.com.au). Phase 2 Customer Workshops: Objectives, engagement activities and results workshops are provided in Table supported AGN presenting 5.6. A full report on the Phase 2 additional proposals to lower In Phase 2 workshops we looked Workshops and results is available carbon along with the resultant to further explore issues of on Gas Matters bill impacts in our Draft Plan and importance, and gain customer (gasmatters.agig.com.au). Phase 3 workshops. input into the development of our plans. In our Phase 2 workshops Customers told us they see value customers told us they value our and are willing to accept a small The objectives of our Phase 2 track record of performance in price increase to enable AGN to workshops were to: relation to safety and reliability, invest in innovation projects. Validate customer feedback and expect this to continue. In all from Phase 1 workshops there was a high level “I am happy to support Share information about of customer support for our innovation projects AGN’s activities proposed approach to invest in Explain how prices are set because it may be of benefit our capital programs to maintain Explore issues of importance current safety and reliability to the consumer or the to AGN and customers Test and seek feedback on service levels. environment in the future” costed proposals “I can see that there are In response to customer feedback Phase 2 workshops were 2.5 some good measures to in Phase 1, we explored hours in duration and included opportunities with customers to opportunities for table discussion maintain the network introduce more digital customer as well as digital voting. reliability being taken” services such as web chat, email Participants were invited to vote etc. Customers told us they expect We presented contextual and rank initiatives they were that digital communication supportive of, using an online information about natural gas and channels will be increasingly carbon emissions to enable further voting tool. available, but are sensitive to discussion around sustainability In Phase 2 we presented an early price. Feedback was that online and the future of gas. Customers services are considered a price forecast to reduce prices by told us that lowering carbon an indicative 8%. In this context preferred investment than SMS emissions is very important to communications. we presented our proposed them with 51% of customers approach for investment in rating it as extremely important. reliability, safety and customer service. We explored areas for “Climate change needs to be further development as identified addressed by all businesses by customers including digital customer service, sustainability but most importantly by a and innovation. We also provided large network” information in relation to the growth of our network. Customers expect us to pursue more opportunities to lower Key topics, information presented carbon emissions. Customers and insights from Phase 2
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Table 5.6: Stage 2 Customer Feedback Summary (Phase 1 & 2)
Topic Engagement Activity Key Insights and Results
Phase 1 Customer Workshops
We provided an overview of our role in the gas Customers expect AGN to deliver a high supply chain, our vision and values, and the level of public safety and feel that safety is context of regulation and business planning. well managed. 31% of participants ranked public safety as Engagement Activity most important. - What does reliability mean for you in your 42% of participants ranked public safety as home/business? their first or second priority. - How satisfied are you with the reliability of Customers highly value an uninterrupted your gas supply? supply of gas in their homes and business - Prioritisation exercise* (see below) Public Safety and are satisfied with current service levels.
& Reliability 52% of participants ranked reliability first or second priority. Customers are satisfied or very satisfied with their current levels of reliability.
Phase 2 Customer Workshops
We presented on the approach we propose to take 92% support for our approach to to maintain current levels of public safety and maintaining current levels of public safety reliability, including our current reliability 96% support for our proposed approach to performance, network design, our control systems, maintaining current levels of reliability maintaining security of supply in outages and mains integrity/protection.
Engagement Activity: - I am comfortable with the proposed approach to maintain current levels of public safety - I am comfortable with the proposed approach to maintain current levels of reliability. Why? Phase 1 Customer Workshops
We provided an overview of our path to Customers are interested in environmental decarbonise gas through hydrogen and considerations and AGN’s role in driving biomethane. sustainable energy solutions in the future 25% of participants ranked ‘Innovation and Engagement Activity: the future of gas’ as first or second priority - Prioritisation exercise* (see below) Phase 2 Customer Workshops Sustainability Customers expect AGN to pursue more & Innovation We presented information about renewable gas and our role in considering ways to lower opportunities to lower carbon emissions
carbon emissions. We shared information on further in addition to existing plans.
our current activities including how we are 87% felt that lowering carbon emissions is preparing our network for sustainable gas and very/extremely important. our pilot project blending hydrogen into the existing natural gas network. 87% of participants indicated they are willing to accept a small price increase to enable AGN to invest in innovation projects. Engagement Activity: 54% indicated they would be prepared to - How important is it to you that we consider pay a price of $2 per annum for this ways to lower carbon emissions? innovation fund. - I would like AGN to pursue more opportunities to lower carbon emissions further? - I am prepared to pay more on my bill every year so that AGN can invest in innovation projects that benefit the energy industry. Why?
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Table 5.6: Stage 2 Customer Feedback Summary (Phase 1 & 2) continued
Topic Engagement Activity Key Insights and Results
Phase 1 Customer Workshops
We provided an overview of our role in the gas Customers would like to interact with AGN supply chain, and discussed examples of when through a variety of channels. The most customers interact with us. We presented our preferred channels for interacting were via proposal to make smart meters available at a fee phone, email, website and SMS/text. for service and we presented information on Customers have a strong preference to where network growth was planned in each of the report a gas leak by phone. local areas. Customers expect timely customer service by knowledgeable staff who demonstrate Engagement Activity: empathy and understanding in responding to - What do you expect from a great interaction queries or resolving issues. with AGN? Many customers are satisfied with current - Participants were asked to complete a meter reading practices, with some communications preference worksheet to customers interested in smart meters and indicate their preferred methods of access to real-time data on gas usage. communicating with us Customer We asked if we should be doing something Experience - different when it comes to meters and meter reading - Prioritisation exercise* (see below)
Phase 2 Customer Workshops
We presented on our customer satisfaction results Customers expect that digital communication and our proposed approach to maintain current channels will be increasingly available but levels of customer service and communication are sensitive to price. channels. We presented our proposal to make Customers consider online services to be a smart meters available as a choice for customers better investment than SMS at a fee for service. communications.
80% of participants expect/strongly expect Engagement Activity: AGN to deliver more services using digital - I expect AGN to deliver more of its services channels between now and 2026. using digital channels between now and 2026. Why? 54% agreed with paying $2.50 on their bill so AGN can invest in improved online - I am prepared to pay $2.50 on my bill per services. annum so that AGN can invest in improved online services. Why? 63% disagreed with paying $5.50 on their - I am prepared to pay $5.50 on my bill per bill per annum so that AGN can invest in annum so that AGN can invest in SMS SMS communications. communications. Why? Phase 1 Customer Workshops
We provided an overview of the residential and While the current price of gas does not business customer billing process and the appear to be a major concern, price and composition of residential/business gas bills. affordability is the top priority for customers. Participants told us affordability means fair and transparent prices, manageable prices Price & Engagement Activity: and forward visibility to avoid ‘bill shock’. Affordability - What does affordability mean to you? - Prioritisation exercise* (see below) Phase 2 Customer Workshops
We presented on how we set prices and our Customers were interested in understanding how price reductions are passed through to forecast price reduction. We discussed how gas distribution prices are set in the context of a consumers. regulatory framework.
Engagement Activity: - Participants were invited to ask questions and participate in group discussion
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Stage 2: Co-design Workshops Ensuring clear accountability for vulnerable customers We ran a series of co-design within AGN. workshops as part of our Stage 2 engagement program to A full report on the Co-design understand how we can better workshops and results is available support vulnerable customers. on Gas Matters All customer and stakeholder (gasmatters.agig.com.au). The co-design process was engagement resources relating facilitated by KPMG, and brought How we are responding to to this Draft Plan are publicly together experts from the social opportunities arising from the Co- available on our online service sector. Co-design is a design workshops in our Draft engagement platform, Gas process by which organisations Plan is addressed in Table 5.7. Matters at collaborate with stakeholders and gasmatters.agig.com.au customers to inform decision 5.5 Summary making. Feedback and Our Resources include
Participating organisations Response Draft Engagement Strategy included: Financial Counsellors We have undertaken a range of for consultation Association of SA; Energy and engagement activities to support Stage 1 Stakeholder Water Ombudsman SA; City of the development of this Draft Engagement Report Playford; National Disability Plan. Information about our Four Services; Anglicare SA; Uniting Staged Approach to Communities; Council of the All customer and stakeholder Ageing SA; Origin Energy; and feedback and how we have Engagement Multicultural Communities Council responded in this Draft Plan is All SARG and RRG Meeting of SA. shown in Table 5.7. agendas, presentation materials and minutes Three rounds of workshops were 5.6 Next steps Stakeholder Information held where participants Sessions on Hydrogen Slide contributed to developing an Consultation on this Draft Plan is understanding of who our open for 2 months. deck KPMG Phase 1 Customer vulnerable customers are, A range of engagement activities Workshop Findings identifying opportunities and are supporting the consultation KPMG Phase 2 Customer generating ideas for supporting period including a further phase of vulnerable customers and customer workshops and Workshop Findings examining shortlisted ideas and continued SARG and RRG Have your say providing feedback for Meetings. We are also offering consideration by AGN. one on one meetings and Gas Matters provides the The following key themes briefings with stakeholders. opportunity to seek further information, and to provide emerged as priorities from the co- A series of consultation questions feedback and submissions in design process for AGN to are included in this Draft Plan. consider: Submissions can be made online relation to this Draft Plan. Understanding customers at Gas Matters better through customer (gasmatters.agig.com.au). relationship management, priority services and empathy in service delivery; Doing more in the community through engagement outreach and education programs; Being proactive in situations when customers are vulnerable; Being present in the affordability debate; and
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Figure 5.7: Customer and stakeholder feedback throughout the Draft Plan
Topic Customer and stakeholder feedback Our response
Pipeline Our South Australian Reference Group and Retailer Based on the stakeholder feedback received services Reference Groups acknowledged that: to date, we propose to maintain the same set of reference and non-reference services in the the pipeline services (reference and non- next AA period. reference services) offered in the current AA period met our customers’ needs; Details of the price and other terms and conditions that will apply to the reference the current reference services, which are a services will be consulted on as we develop subset of pipeline services, are appropriate to our Final Plan. continue in the next AA period; and Due to low demand, Out of Hours Special Stakeholders agreed that the current list of Meter Reading and Same Day Services will reference services is appropriate. They also noted remain non-reference services. two non-reference services (Out of Hours Special Meter Reading and Same Day Service) could become reference services in future AA periods if
there is significant demand for those services.
On 27 June 2019 we provided our reference service proposal to the AER for the 2021/22 – 2025/26 AA period. The proposal was developed on the basis of feedback provided by our customers and stakeholders.
The AER consulted on this proposal with stakeholders and in November 2019 approved our proposal.
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Figure 5.7: Customer and stakeholder feedback throughout the Draft Plan
Topic Customer and stakeholder feedback Our response
Price & Customers told us that price and affordability is We are proposing to reduce prices for affordability their top priority. customers by 8% the first year of the next period, followed by real increases of 1.2% Customers were keen to understand how gas consistent with the growth in our capital distribution prices are included in their final bill – base. We note that this proposed price path and how any savings might be passed on from their means that customers will pay around 20% retailer. less (before the impact of inflation) in Stakeholders supported AGN’s proposal to consider 2025/26, than they did in 2010/11. opportunities to better support vulnerable We have had regard for the price impact of customers for inclusion in this Draft Plan. individual decisions as we developed the Draft Stakeholders noted the complexities in the role Plan. of a gas distribution business – for example the In Chapter 7 (operating expenditure) and business community notes that subsidies given Chapter 8 (capital expenditure) we have to the residential sector may increase pressure demonstrated that our expenditure proposals on the business sector. are cost efficient. Stakeholders participating in the Co-design In our engagement activities we have workshops identified a number of opportunities for ensured we gain feedback from customers on AGN to consider in improving services for vulnerable proposed investments in the context of customers. potential bill impacts.
We will again engage with Retailers to encourage that they pass on of any savings to customers when our new prices take effect on 1 July 2021.
We are considering investing in a Vulnerable Customers Assistance Program to deliver service improvements for the most vulnerable in our community. We will further test and explore this in our Draft Plan consultation.
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Figure 5.7: Customer and stakeholder feedback throughout the Draft Plan
Topic Customer and stakeholder feedback Our response
Customer Stakeholders and customers have provided positive We are proposing to maintain investment in experience feedback on our current performance in terms of customer service and achieve 8.2 out of 10 or customer service, in particular that AGN tracks and above in our customer satisfaction survey. sets targets for customer satisfaction levels. Our capex proposal (chapter 8) includes Customers told us they expect timely customer investment of $32 million on projects and service by knowledgeable staff who demonstrate programs to continue to meet customer empathy and understanding in responding to service expectations. queries or resolving issues. It was noted that some Our capex investment proposal includes customers and stakeholders expressed a preference improving online services via digital channels for an Australian based contact centre. in response to feedback from customers. We Many customers are satisfied with current meter will be further testing our revised proposal reading practices, with some customers interested with customers as part of this Draft Plan in smart meters and access to real-time data on gas consultation. usage. Based on customer feedback we are not Customers expect that digital communication investing in a smart meter roll out in our Draft channels will become increasingly available but are Plan. We consider a potential option is to sensitive to price. Customers consider online offer smart meters on a fee for service to services to be a better investment than SMS customers, however this is not considered as communications. part of this AA review.
54% agreed with paying $2.50 on their bill so AGN can invest in improved online services.
63% disagreed with paying $5.50 on their bill per annum so that AGN can invest in SMS communications.
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Figure 5.7: Customer and stakeholder feedback throughout the Draft Plan
Topic Customer and stakeholder feedback Our response
Our capital Customers expect AGN to deliver a high level of Our totex forecast (combined opex and and public safety and feel that safety is well managed. capex) for the next AA period are consistent operating with the levels we expect to incur in the expenditure 92% of customers support our approach to current AA period. proposals maintaining current levels of public safety The level of totex enables us to maintain Customers highly value an uninterrupted supply of safety, reliability and the service levels gas in their homes and business and are satisfied expected from our customers. with current service levels. 96% of customers support for our proposed approach to maintaining Our opex forecast is discussed in Chapter 7 of current levels of reliability this Draft Plan, and has been developed applying standard regulatory methodologies Stakeholders noted an overall capex spend broadly in line with the previous regulatory period, with an Our capex forecast is discussed in Chapter 8 ongoing focus on public safety, reliability, growing of this Draft Plan and is in line with current the network and customer service outcomes. levels, responding to customer and stakeholders to maintain our safety, reliability Stakeholders and customers noted key features of and service performance. the proposed capex program, including: We are proposing to complete the mains replacement our largest expenditure item replacement of all remaining low-pressure over the next period to maintain public safety; cast iron, unprotected steel and other mains – a further 550 km in addition to the 345 km IT expenditure forecast consistent with current we will have replaced in the current AA levels of expenditure, with more investment in period (Chapter 8). network monitoring and potentially digital
services;
Augmenting the network to meet demand and maintain reliability; and
Net customer growth of 30,000 - a reduction on growth capex is largely due to the forecast drop-off in new dwellings.
Stakeholders highlighted the importance of converting to polyethylene pipes and replacing cast iron mains for safety, reliability, to minimise gas losses and to prepare for the future.
Stakeholders were comfortable with the preliminary expenditure proposals presented at SARG Meeting #5 in October. It was also acknowledged by SARG members that preliminary expenditure proposals were developed applying accepted regulatory methodologies and are in line with our current levels of expenditure and appear reasonable.
Rate of Stakeholders acknowledged our intention to adopt We have accepted the AER’s Rate of Return return the AER’s Rate of Return Guidelines, as well as Guidelines, as described in Chapter 10 of this determination of the tax allowance of zero, Draft Plan. consistent with the approach taken in the recent AER tax review. Stakeholders noted this is We have accepted the outcome of the AER’s consistent with submitting a plan that is capable of Tax Review. The forecast tax allowance for being accepted. the next AA period is zero.
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Figure 5.7: Customer and stakeholder feedback throughout the Draft Plan
Topic Customer and stakeholder feedback Our response
Capital Base Stakeholders acknowledged complexities around As outlined in chapter 9 of our Draft Plan we the future of the network given the ongoing have continued to apply the asset lives that decarbonisation of energy supply, particularly how were approved by the AER for the current AA this could affect the economic life of gas period. assets/networks and therefore depreciation. While we recognize that there is some Stakeholders acknowledged that AGN is proposing uncertainty around future energy models, we to determine depreciation in accordance with that see a future for our gas distribution business approved by the AER for AGN’s Victorian network, through advances and investment in including in relation to the treatment of the residual renewable gases, in particular hydrogen. asset value of mains and services that have been Therefore at this time we do not consider any replaced as part of the mains replacement changes to the depreciation profile is required program. in order to transition to a low carbon economy. We have applied the same approach to that approved by the AER for our Victorian network whereby mains that have been replaced or removed from the capital base.
Demand Stakeholders noted AGN’s approach to demand As outlined in chapter 12 of this Draft Plan, forecast forecasting is based on historic trends with our demand forecast applies methodologies adjustments for projected energy prices, weather accepted by the AER for our most recent and dwelling starts. The approach h is consistent South Australian and Victorian reviews. with our last South Australian and Victorian and The forecast are based on our historic trends Albury reviews. but also take into account future projections Our forecasting approach is also consistent with the of dwelling growth, energy prices and the Australian Energy Market Operator (AEMO) for its impact of weather. Gas Statement of Opportunities.
Retailers acknowledged the trend shown in demand forecasts are consistent with their own observations and expectations of demand.
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Figure 5.7: Customer and stakeholder feedback throughout the Draft Plan
Topic Customer and stakeholder feedback Our response
Incentives Stakeholders noted that AGN is considering a We consider incentive mechanisms to be an capital expenditure sharing scheme (CESS) to important part of a regulatory framework that compliment the current opex incentive scheme and help deliver efficiencies to customers in a that consideration is also being given to customer timely manner. service and innovation incentive schemes. We are therefore proposing the continuation of the AER’s opex incentive mechanism There was discussion around the incentive currently applying in South Australia, as well mechanism, noting that while they can work to as a capex incentive mechanism consistent deliver better outcomes for customers, they need to with that approved by the AER for our be appropriately specified to work as intended. Victorian gas network We are considering an innovation scheme and will further test customer support for this as we engage on our Draft Plan. Incentive schemes proposed are outlined in Chapter 11 of this Draft Plan.
Future focus Customers acknowledged the increasing mix of We have developed our proposals within this renewable electricity in the energy sector and the Draft Plan with regard to the long-term uncertainty around future gas deliver models. interests of customers.
Stakeholders mentioned that the Future of Gas as a Our demand forecast in Chapter X takes into account increasing renewable energy supplies topic should be broadened to recognize external in the market. factors that impact on the future such as supply and demand, and the impact on the wholesale gas We are considering establishing an education market for business and industry. centre and learning program at Hydrogen Park SA to showcase the future of gas in a Future of Gas as topic should also be considered in low carbon economy. the context of innovation, and potential regional development opportunities. We are considering an innovation scheme and will further test customer support for this Stakeholders were keen to understand how a as we engage on our Draft Plan. Incentive transition would work over time to increase the schemes proposed are outlined in Chapter 11 percentage of blended renewable gas. Stakeholders of this Draft Plan. were also keen to understand any additional We are considering replace some of our considerations for increasing blended gas use UAFG with renewable gas as part of our including any impacts on the life of assets or gas operating expenditure in Chapter 7. appliances, and any broader safety considerations.
Some customers commented that further continuing education on the future of gas is warranted, likely leveraging Hydrogen Park SA.
Customers expect AGN to pursue more opportunities to lower carbon emissions further in addition to existing plans.
87% felt that lowering carbon emissions is very/extremely important.
87% of participants indicated they are willing to accept a small price increase to enable AGN to invest in innovation projects. 54% indicated they would be prepared to pay a price of $2 per annum for this innovation fund.
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Pipeline and Our proposed pipeline and reference services reference for the next AA period are consistent with services those currently provided by the South Australian distribution network.
IN THIS CHAPTER: We offer a range of reference service proposal pipeline services to meet decision, unless there has been a We propose to maintain material change in circumstances. our customers’ needs. consistent reference and On 27 June 2019 we provided our non-reference services in In the current AA period we have reference service proposal to the the next AA period. offered a number of different AER for the next AA period. This haulage and ancillary services. Our proposed reference proposal, which was developed on the basis of feedback provided by services include a range of The haulage services and most commonly used ancillary services our customers and stakeholders haulage and have been classified as reference and the reference service factors complementary ancillary services. These services, which set out in the NGR, provided for a services. have accounted for 99.5% of the consistent set of reference and revenue earned in the current AA non-reference services in the next period, have been subject to the AA period. reference tariffs approved by the The AER consulted on this AER in 2016. proposal with stakeholders and in A small number of less commonly November 2019 approved our used ancillary services have been proposal. classified as non-reference services, with the price reflecting 6.2 Customer and the cost of providing the services stakeholder by AGN. engagement
Based on the stakeholder When developing our reference feedback received to date, we service proposal, we met with our propose to maintain the same set SARG and RRG. Through this of reference and non-reference services in the next AA period.
The following sections provide Reference service factors further detail on the reference and The reference service factors in non-reference services we the NGR require consideration to propose to offer in the next AA be given to: period. Details of the price and actual and forecast demand for other terms and conditions that the service and the number of will apply to the reference services prospective users of the are provided in subsequent service; chapters of this Draft Plan. the extent to which the service 6.1 Regulatory is substitutable with another framework reference service; the feasibility of allocating This Draft Plan describes all of the costs to the service; pipeline services that we can the usefulness of specifying a reasonably provide. It also service as a reference service specifies the reference services in supporting negotiations and we intend to provide, which must dispute resolution for other be consistent with the AER’s services; and the likely regulatory cost. 56 DRAFT PLAN 2021/22-2025/26 PIPELINE AND REFERENCE SERVICES
engagement process, we asked dispute resolution for other whether: pipeline services; and the services offered in the Engagement insights will minimise the regulatory current AA period met our cost for all parties. Customers support the customers’ needs; continuation of our existing 6.3.2 Non-reference the current reference services set of reference and non- services are appropriate to continue in reference services. the next AA period; and In the next AA period, we also 6.3 Pipeline services propose to offer a number of non- there were any additional reference services. These services services that should be Table 6.1 sets out the reference have been classified as non- reference services. and non-reference services we reference services because, in propose to offer in the next AA Our reference groups supported contrast to reference services: period. the retention of the existing the demand for these services reference and non-reference The classification of the services in is relatively low and in most services for the next AA. this table as either reference or cases unpredictable; and/or non-reference services is Stakeholders considered the consistent with the classification the cost of providing most of current services offered were that applies in the current AA these services varies markedly appropriate for the next AA period. It is also consistent with period. Some members of our our July 2019 reference service Retailer Reference Group proposal, which the AER approved suggested two additional services in November 2019. (Out of Hours Special Meter Reading and Same Day Service) As Figure 6.1 shows, the proposed should be reconsidered for future reference services have accounted AA periods, but given low demand for 99.5% of the revenue earned should remain ancillary non- by the South Australian network in reference services at this point. the current AA period, while non- reference services have accounted No additional services were for just 0.5%. considered necessary by reference group members. 6.3.1 Reference After submitting our Reference services Service Proposal, the AER In the next AA period, we propose provided stakeholders an to offer three haulage services opportunity to comment before and six ancillary services as making its final decision. The AER reference services. received two submissions which were consistent with the feedback Consistent with the reference we had received. services factors, these services: are the most sought after services by our customers;
are not generally substitutable with other reference services; have largely predictable costs that can either be attributed to individual users or reasonably allocated across users of a particular service;
can aid prospective users in access negotiations and
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Figure 6.1: SA distribution network revenue share 1 July 2016 – 30 June 2019
depending on the specific 1.4% 0.5% customer requirements.1 7.1% Two of the proposed non- reference services (i.e. the out of 14.0% hours special meter reading and same day service) are also substitutes for reference services.2 While we are not proposing to define these services as reference services in the next AA period, we 77.0% understand customer preferences are changing. We will therefore re-evaluate the classification of Domestic haulage reference service Commercial haulage reference service Demand haulage reference service Ancillary reference services services for the subsequent AA Non-reference services period and consult with our stakeholders at the time. 6.4 Summary
We propose to maintain the current set of reference and non- reference services in the next AA period. Our customers support this approach, which is also consistent with our Reference Services Proposal approved by the AER in November 2019.
1 For example, the cost of moving or removing a meter can range from $100 to $77,000, depending on the customer’s site and needs 2 This means that if customers are dissatisfied with the terms of access to these services, they can have recourse to the reference service.
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Table 6.1: Summary of pipeline services for the South Australian distribution network 2021/22-2025/26
Pipeline services General description
Haulage reference services Domestic haulage service A haulage reference service that comprises the delivery of gas through an existing domestic Delivery Point (DP).
Demand haulage service A haulage reference service that comprises the delivery of gas through an existing demand DP. A DP is a demand DP at a given time if: (a) that DP is not a domestic DP at that time; and (b) the quantity of gas delivered through that DP during the then most recent metering year was equal to or greater than 10TJ in total. Commercial haulage service A haulage reference service that comprises the delivery of gas through a commercial DP. Ancillary reference services Special meter reading A meter reading for a DP and provision of the associated meter reading data, that is in addition to the scheduled meter readings that form part of the haulage reference services (Special Meter Reads will be charged in accordance with location as either metropolitan or non-metropolitan). Disconnection The use of locks or plugs at the metering installation of a domestic or commercial DP in order to prevent the withdrawal of gas at the DP.
Reconnection Action to restore the ability to withdraw gas at a DP, following an earlier disconnection (that is, the removal of any locks or plugs used to isolate supply, performance of a safety check and, where necessary, the lighting of appliances). Meter and Gas Installation Test On-site testing to check the measurement accuracy and soundness of a metering installation and the gas installation downstream of the metering installation.
Meter Removal Removal of a meter in order to prevent the withdrawal of natural gas at the DP. Meter Reinstallation Reinstallation of a meter, performance of a safety check and lighting of appliances where necessary. Ancillary non-reference services Meter Alter Position /Removal When a customer is requesting the relocation of an existing gas meter to a new position, or the removal of a second meter on the premises.
Out of Hours Special Meter Request for an appointment to read a meter (Special Meter Reads are charged in Reading accordance with location as either metropolitan or non-metropolitan).
Same Day Service Request for a service on the same day as the request is made (the service is charged in addition to the charge for the requested service). Relocate/Remove Service Pipe Relocate the service or "Inlet" pipework. Cut-off Service in Street for Debt Requested by retailer, or by distributor as a matter of safety, when disconnection of supply is intended to be longer term due to non-payment of outstanding account by customer.
Reconnect Service in Street After Reconnection of gas supply, previously disconnected in the street, following satisfactory Cut-Off payment by customer (or other agreed arrangement).
Upgrade Service Request Increased gas load requires a larger capacity of service line to be installed. Other Negotiated Service A network service that is different from the Reference Services, on terms and conditions that differ in from the general terms and conditions.
1. The haulage reference services include the provision of unaccounted for gas and all services that are necessary in order for AGN to comply with its obligations.
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Our operating expenditure has fallen in the Operating current period and we will pass on the expenditure savings to our customers in the next AA period.
IN THIS CHAPTER: The operating consideration of the individual Our opex forecasts have expenditure (opex) we factors that drive those costs. been developed using the incur supports the safe, On an aggregate basis, our opex base-step-trend efficient and reliable is forecast to be $354 million over methodology approved by the next AA period (see Table delivery of gas to homes the AER. 7.1). Excluding the effect of our and businesses every proposed change in capitalisation Opex in the current AA day. It ensures we can policy, this is around 3% period is forecast to be meet the service ($10 million) higher than what we 11% lower than our expectations of our expect to incur in the current AA allowance due to our period (forecast to 30 June 2021). customers and the day- merger with AGIG in 2017, We achieved savings in the the benefits of which will to-day needs of our current period largely due to one- be passed onto our workforce. off integration benefits from our merger with AGIG in 2017. customers in the next AA Consistent with our approach to period. forecasting opex, we have This increase in opex can be adopted the AER’s base-step- attributed to the increased costs Our opex forecast will trend methodology. This means associated with unaccounted for ensure we continue to for most opex items we look at gas (UAFG), which reflects the provide the safe, efficient, the total costs we are incurring higher gas prices that we expect reliable and high-quality now and project those costs to pay. Across all other categories service our customers forward, but for some items we we have been able to keep costs value. develop specific forecasts having for the next AA period at the same level we will incur in the current
Table 7.1 Total forecast opex ($million, 2020/21)
Current Next Drivers for change AA AA period period
Opex (ex UAFG) 281.5 281.3 Embedded efficiencies made in the current period and the ‘trend’ component (real cost escalation and customer growth) of our opex forecast
Proposed change in - 23.4 We are proposing to reduce capitalisation the level of overheads that are capitalised into our asset base
UAFG 39.0 48.8 Reflects the increase in the cost of gas
Total opex 320.5 353.6
Note: Totals may not add due to rounding
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AA period, even when taking into manner as the efficiencies All numbers quoted in this section account real increases in labour achieved in this AA period will be. are expressed in 2020/21 dollars, costs and servicing an additional unless otherwise stated. The following sections provide 30,000 customers. further detail on the standard our 7.1 Regulatory Although a modest increase in forecasts must meet under the framework opex is expected in the next AA regulatory framework, the period (as shown in Figure 7.1 forecasting method we have used Our AA proposal must include the and Figure 7.2), the incentives and our forecasts for the next AA forecast opex for the next AA provided by the operation of the period. Further detail is also period. Efficiency Benefit Sharing Scheme provided on how we have (EBSS), coupled with our internal performed in the current AA In keeping with the NGR, our and external controls, will period and how we ensure the forecast must reflect the continue to ensure that the opex expenditure we incur is both expenditure that would be we incur is both prudent and prudent and efficient. incurred by a prudent gas pipeline efficient. This will also ensure that business, acting efficiently, in any cost savings are passed accordance with good industry through to customers, in the same practice, to achieve the lowest
Figure 7.1: Opex excluding UAFG
$100
$90 $340 million $305 million $80
$70
$60
$50
$40 $282 million $281 million $30
$20 Opex ex UAFG ($million, 2020/21) ($million, UAFG ex Opex $10 Current AA Period Next AA Period $0 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23 2023/24 2024/25 2025/26 Actual & Forecast Allowance Forecast (excl. OH)
Figure 7.2: Actual and forecast UAFG
$12
$10
$8
$6 $49 million
$4 $39 million
$2
UAFG ($million, 2020/21) ($million, UAFG Current AA Period Next AA Period $0 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23 2023/24 2024/25 2025/26
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sustainable cost of providing services to our customers. Our forecasts must also be arrived Engagement insights at on a reasonable basis and Customers expect a high level represent the best forecast or of public safety and feel that estimate possible in the safety is currently well circumstances. managed. 7.2 Customer and Customers highly value an stakeholder uninterrupted supply of gas in their homes and businesses engagement and are satisfied with current Customers told us their top levels priorities are price/ affordability, Customers and stakeholders reliability of supply, and support a proposed approach maintaining public safety. to maintaining current levels Customers highly value our track of safety reliability. record of performance for both Customers and stakeholders reliability and public safety, and are satisfied with current expect this to continue. With this customer service levels, with in mind, our opex proposal is preference for interacting based on maintaining current with customers through a levels of reliability and safety. variety of digital channels. Customers expect timely customer Stakeholders have supported service by knowledgeable staff our approach to preparing our who demonstrate empathy and operating expenditure understanding in responding to proposals in the development queries or resolving issues. of this Draft Plan. Customers and stakeholders are satisfied with our current customer service levels, however they would like to see more digital 7.3 How we develop customer services be introduced our opex forecast over time. Our opex proposal supports maintaining our strong Our opex forecast for the next AA track record of customer service. period has been developed using the base-step-trend approach for We have developed our opex our opex excluding UAFG and proposal in consultation with debt raising costs. A bottom-up stakeholders. We presented our approach has been used to draft opex proposal to both develop category specific reference groups in October 2019 forecasts for opex categories that to seek feedback on our cannot reasonably be estimated investment priorities and levels of using the base-step-trend expenditure. Stakeholders were approach (i.e. debt raising and supportive of how we have UAFG costs). developed our proposal. They were also keen to understand that The use of this approach is our costs are efficient. We have consistent with the AER’s demonstrated this section 7.3 of preferred approach and the this Chapter. approach we have used in prior AA periods.
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Figure 7.3 illustrates the key Figure 7.3: Forecasting method used for opex elements of this approach.
7.4 Our opex forecast for the next AA period
The following sections set out how each element of our opex forecast has been developed.
7.4.1 Base year opex Under the base-step-trend approach, the actual costs incurred in the penultimate year of the current AA period are used as the base for forecasting costs in the next AA period. This year represents the most up to date actual cost information available at the time that the AER will make its decision. The penultimate year of the current AA period is 2019/20. At this point in time we do not have the actual costs for this year. We have therefore had to develop a forecast of the 2019/20 costs for this Draft Plan. This forecast is based on the actual opex incurred to December 2019 and a forecast for the remaining six months of the financial year. When we submit our Final Plan to the AER on 1 July 2020, more information on our actual opex in 2019/20 will be available. We intend therefore to update this forecast with nine months of actual data and three months of forecasts when we submit our Final Plan. By the time the AER makes its Draft Decision towards the end of 2020, we will be able to provide a full year of actual opex for the 2019/20 base year.
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Removal of non-recurrent capitalised. At this time, we have and debt raising costs. We have opex identified a portion of these therefore excluded $7 million from activities which are more akin to the 2019/20 forecast expenditure As noted in Figure 7.3, once the operating expenditure than capital to remove the costs associated base year costs are determined, expenditure. These activities are: with UAFG, and $1 million for debt they must be adjusted to remove raising costs. any non-recurrent costs. costs of senior management involved in the management Base year opex used for The opex we have forecast to of capital projects; forecasting incur in 2019/20 reflects our expenditure on recurrent costs associated with The base year opex that we have activities. It has not therefore procurement of vehicles; and used for the purposes of the Draft been necessary to make an indirect costs to support the Plan is $63 million. As noted adjustment for non-recurrent provision of the above above, this amount will need to be costs. activities such as human updated ahead of the Final Plan resources and HSE. and following the AER’s Draft Accounting for changes to Decision to reflect the actual costs capitalisation of overheads To account for this capitalisation incurred in 2019/20. The base year costs must also be policy change in the opex forecast, 45% of the forecast While some revisions may need to adjusted to account for any be made, the revised costs can be changes in the treatment of costs. capitalised overheads for 2019/20 have been included in the base assumed to be both prudent and Our capitalised overheads account year opex. This results in a efficient given the operation of for around $43 million of $19 million increase in the both: expenditure per year. These 2019/20 base year expenditure. the EBSS (see Chapter 12), overheads relate to activities An offsetting change has also the objective of which is to undertaken by our lead contractor been made to our capex forecast provide a continuous incentive APA, such as: for the next AA period, resulting in to pursue efficiencies and cost of senior management a capitalised overhead rate of achieve the lowest sustainable involved in the management 5.1% compared to 10.1% in the cost of providing services in of capital projects; current AA period. every year; and network analysis, design, Given this, the reclassification of our internal and external mapping and costing support these costs will have no effect on controls on asset in relation to network our overall costs, because the management, procurement extensions and modifications; increase in opex arising as a result and financial governance (see of the reclassification will be offset section 8.7), the objectives of costs associated with by a reduction in capex. which are to ensure we procurement of vehicles; Reclassifying these activities as undertake opex in a prudent technical assurance, which opex will have the ancillary benefit and efficient manner, in includes technical audits, of assisting to maintain the long- accordance with good employee training and term competitiveness of gas by industry practice. competency assessment; reducing the growth in our asset To this end, the AER noted in its costs of providing design and base. decision for the current period that: engineering services for high- Removal of opex categories to pressure and non-standard be forecast separately “AGN has been subject to [an] distribution assets; and incentive framework for a number The final adjustment that must be of access arrangement periods, indirect costs to support the made to the base year costs is to including the application of an provision of the above remove those opex categories for efficiency carryover mechanism activities such as human which category specific forecasts for opex. In theory, AGN as a resources and HSE. are required to better estimate profit maximising firm should efficient costs. We are in the process of reveal its efficient costs over time, reviewing the types of activities As noted above, we have and these can be used to forecast included within our overhead developed separate forecasts for opex into the future. Unless we costs which we have typically the costs associated with UAFG have evidence that the revealed
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opex in a proposed base year is preparing our regulatory the AER benchmark weights as materially inefficient, we use the information notices; follows: 4 revealed costs of the service higher IT opex driven by labour costs are assumed to provider for our alternative opex recent improvements to our account for 59.7% of our forecast.”3 cyber security framework, as opex and are forecast to grow The costs we incur in the base well as the new platform that in real terms by an average year will therefore provide a will support digital customer annual rate of 0.8% per year prudent and efficient basis for services; and over the next AA period; and forecasting opex in the next AA increased asset operating materials costs are assumed period. costs associated with our to account for 40.3% of our Table 7.2: Establishing the base year capex program such as for opex and are assumed to for forecasting opex in the next AA the Mount Barker pipeline and grow in real terms by 0% per new Gawler Gate Station. year over the next AA period. period The growth rate assumed for Category 2019/20 7.4.3 Trend labour costs is based on the forecast average of the Wage Price Index The final element of the base- forecasts for Electricity, Gas, step-trend approach requires Total opex 62.4 Water and Wastewater Services consideration to be given to the developed by BIS Oxford and extent to which our costs are Minus UAFG 9.5 Deloitte Access Economics (as expected to change over the next shown in Table 7.3). Minus Debt 1.0 AA period as a result of: The materials cost growth rate is raising costs input cost escalation; based on the growth rate Base year for 52.0 output growth; and assumed by the AER in recent regulatory decisions for AGN, forecasting productivity growth. which is zero. These three factors are The application of these accounted for through the 7.4.2 Step changes assumptions results in a real (i.e. application of the trend rate of before inflation) average annual The next element of the base- change to the base year opex input cost escalator of 0.5% per step-trend approach requires any and, where relevant, any step year over the next AA period (see ‘step changes’ in costs in the next changes. AA period to be identified. Step Table 7.4). changes may arise as a result of While we are still having some Output growth changes to legislation, regulatory work undertaken by independent obligations or new activities. experts on these factors, for the The output growth factor accounts purposes of the Draft Plan we for the additional opex we will While we have identified a have assumed a trend rate of incur as a result of the forecast number of potential step changes change of 1.4% per year. growth in output. in opex over the next AA period, we don’t intend to seek additional Further detail on the key funding for these changes at this determinants of this rate of time. Instead we intend to absorb change is provided below. these step changes into our cost Input cost escalation base. The input cost escalator accounts Examples of positive step changes for costs that are expected to we expect in the next AA period increase at a different rate than are: inflation (real cost escalation). recent increases in the To calculate the input cost regulatory requirements for escalation rate we have applied
3 AER 2015, “Attachment 7: Operating Expenditure | Draft Decision Australian Gas Networks 2016 to 2021”, November 2015, pg. 7- 14. 4 These weights are based on the AER’s benchmark weights.
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Our proposed output growth factor would have resulted in an factor is based on the most recent increase to our opex forecast for AER approved approach applied that period. by Jemena for its New South Similarly, we proposing to apply a Wales gas distribution network. It productivity growth estimate of has therefore been calculated 0% per year in this Draft Plan and having regard to the forecast note we have again proposed to growth in: absorb projected increases to customer numbers over the opex (as outlined earlier) rather next AA period; and than seeking an expanded opex forecast. kilometres of network over the next AA period. Figure 7.4 below shows our opex per customer relative to customer These forecasts, which are set out density, where customer density is in Chapters 8 and 13, have been the total number of customers per weighted consistent with the AER kilometre of mains. benchmark rates, with customer numbers given a 51% weighting The AER has expressed: and kilometres a 49% weighting. “… the most significant output of This is a change from our previous distributors is customer numbers. AA and is more reflective of the The numbers of customers on a drivers of our costs. distributor’s network will drive the demand on that network. Also, The application of these the comparison of inputs per assumptions results in an average customer is an intuitive measure annual output growth rate of that reflects the relative efficiency 0.9% per year over the next AA of distributors.” 5 period (see Table 7.5). Our opex per customer is within Productivity growth the range of all gas distributors In applying the ‘base year roll- included in the sample. This forward’ approach, the AER provides further support that our considers whether there should be base year opex reflects efficient an adjustment to capture the costs. benefits of any potential future efficiency gains made by the Figure 7.4: Economic Insights opex per customer, adjusted for GDB size and dwelling business. density, relative to customer density (average 2015-2019) We considered this issue in our recent AGN Victoria and Albury AA. We found the cost function analysis methodology relied upon by the AER to forecast productivity in the electricity industry produced a declining forecast of productivity growth for AGN Victoria and Albury over 2018-2022. We applied a productivity growth estimate of 0% per year in our AGN Victorian and Albury AA, which was accepted by the AER, as a declining productivity growth
5 AER, “Electricity distribution network service providers annual benchmarking report”, November 2014, pg. 23.
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Table 7.3: Calculation of annual real labour cost escalation
Labour cost 2020/21 2021/22 2022/23 2023/24 2024/25 2025/26 estimates
BIS Oxford (A) 1.13% 1.28% 1.44% 1.60% 1.33% 1.26%
Deloitte Access - 0.40% 0.30% 0.50% 0.40% 0.40% Economics (B)
Annual labour cost 1.13% 0.84% 0.87% 1.05% 0.87% 0.83% escalation (average of A and B)
Table 7.4: Calculation of annual input cost escalation (weighted average of real cost escalation for labour and materials)
Category Weight 2020/21 2021/22 2022/23 2023/24 2024/25 2025/26
Labour 59.7% 1.13% 0.84% 0.87% 1.05% 0.87% 0.83%
Materials 40.3% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00%
Annual input cost 0.67% 0.50% 0.52% 0.63% 0.52% 0.50% escalation
Table 7.5: Calculation of the output growth factor
Category Weight 2020/21 2021/22 2022/23 2023/24 2024/25 2025/26
Customer 50.6% 1.34% 1.36% 1.35% 1.32% 1.27% 1.23% numbers
Network 40.4% 0.96% 0.53% 0.53% 0.53% 0.51% 0.50% length (km)
Weighted output 1.15% 0.94% 0.94% 0.92% 0.89% 0.86% growth factor
leaks, metering inaccuracies Our UAFG forecast has then been 7.4.4 Category specific and/or gas theft. calculated by multiplying: forecasts While we have engaged an the three-year average As noted above, separate independent expert to estimate volume of UAFG in the last forecasts have been developed for the volume of UAFG for the SA three years; by UAFG costs and debt-raising costs. network over the next AA period, The way in which these costs the forecast average price of the results of this work are not yet have been estimated is outlined gas, which is based on available. below. current market indications for For the purposes of this Draft Plan securing firm gas to meet our UAFG forecast we have therefore assumed the UAFG quantity requirements UAFG is the difference between volume of UAFG is equal to the in the next AA period. the quantity of gas entering the three-year average volume of This method produces a forecast network and the quantity of gas UAFG our SA network has of $49 million for the next AA delivered to our customers. This experienced in the last three period. difference may arise as a result of years.
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We are aware of an opportunity Debt-raising cost forecast The increase can largely be to purchase renewable/carbon attributed to our proposal to Debt-raising costs are the costs neutral gas from a bioenergy expense rather than capitalise a businesses incur when raising or project in the next AA period portion of our overhead costs. refinancing debt and the costs which could provide around 20% While this has resulted in an associated with maintaining a of our total UAFG requirements. increase in our forecast opex, it debt facility. We also understand sustainability has also resulted in an offsetting is important to our customers. At Our debt-raising cost forecast has reduction in our forecast capex. 7.5 below we outline a potential been calculated using the AER’s On a net basis therefore, our total future of gas initiative for UAFG standard benchmark method. expenditure is unchanged. that we are seeking customer The application of this method Excluding the effect of the and stakeholder feedback on to produces a debt-raising cost changed capitalisation policy, our better understand if we should forecast of $4 million for the next opex in the next AA period is incorporate this as part of our AA period. around 3.0% ($9.6 million) higher plans. than what we expect to incur in In a similar manner to our the current AA period. 7.4.5 Summary current AA, we are proposing to As noted above, we will need to deal with the uncertainty Figure 7.5 and Table 7.6 set out make some revisions to this opex surrounding the forecast gas our forecast opex for the next AA forecast when submitting our Final price through the inclusion of a period. Plan to the AER and in response ‘true-up’ adjustment in our tariff As this table shows, we expect to to the AER’s Draft Decision. variation mechanism. incur $358 million in opex over We will, for example, update our In effect, this means that if the the next AA period, inclusive of estimate of the 2019/20 base year actual price we are required to $4 million of debt raising costs. costs with the actual costs pay for gas is lower (higher) than This is 10% higher than what we incurred in that year, once the forecast, then the lower (higher) expect to incur in the current AA information is available. price will be passed through to period (forecast to 30 June 2021). our customers. We may also need to revise the UAFG forecast to reflect the outcome of the work currently Figure 7.5: Opex in the next AA period by category ($million, $2020/21) being carried out by independent experts. Change in capitalisation Debt Raising Our opex in the next AA period Costs, $4.5 , 1% of overheads, aligns with our vision by: $23.4 , 6% delivering for customers – we Network will respond to leaks on our Development, network (one of the most $21.5 , 6% important activities we UAFG, $48.8 undertake to ensure public , 14% safety) and maintain our network assets as required by our asset management plans (AMPs), along with other operational activities to maintain our strong safety, Administratio Operating & reliability and customer n & General, Maintenance, $34.8 , 10% $225.0 , 63% service performance; being a good employer – we will undertake workplace health and safety programs, and employee and contractor training and development initiatives to maintain a
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healthy, safe and skilled workforce; and being sustainably cost efficient – we will pass through opex savings made in the current period to our customers and incur similar levels of opex to that incurred in the current AA period (excluding the effect of the change in capitalisation policy), while facing upward cost pressures. We want to ensure that the services we provide will deliver for all South Australians, including those in vulnerable circumstances. While we do already have some support measures in place, we are considering opportunities where we could do more to provide further support to those in need. Given how important sustainability is to our customer and stakeholders, we have outlined further opportunities we could pursue over the next AA period. We are seeking customer feedback on these additional initiatives before incorporating them as part of our plans.
Table 7.6: Opex forecast summary ($ million, 2020/21)
2021/22 2022/23 2023/24 2024/25 2025/26 Total
Base year opex forecast 52.9 52.9 52.9 52.9 52.9 264.5
Step changes ------
Change in capitalisation 5.4 5.6 4.1 4.3 4.1 23.4
Trend 1.7 2.5 3.4 4.2 5.0 16.8
UAFG 9.5 9.6 9.8 9.8 10.0 48.8
Total opex forecast (ex 69.6 70.7 70.2 71.2 72.0 353.6 debt raising costs)
Debt raising costs 0.9 0.9 0.9 0.9 0.9 4.5
Total opex 70.4 71.5 71.1 72.1 72.9 358.1
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7.5 Potential Vulnerable customer assistance program vulnerable customer Some opportunities which we are considering include: initiatives A priority services register that allows us to proactively contact customers in circumstances such as outages This section sets out potential new initiatives we could Rebates or discounts for connection fees or plumbing assistance incorporate into our business Policy advocacy for vulnerable customers plans over the next AA period as part of a program to improve Specialised training programs for customer facing service roles services for vulnerable customers. As discussed in Chapter 2, we are one of the founding businesses across the energy supply chain who have committed to the Energy Charter. The Energy Charter seeks to bring energy business together to deliver energy for a better future, which includes supporting customers facing a vulnerable circumstances as a key principle. We know affordability and helping those in need is important to our customers and stakeholders. Customers in vulnerable circumstances can include people with a disability, those who are chronically sick, older Australians, and also those in financial hardship. We have been actively engaging with experts in the social service sector to develop potential new ways in which we could support vulnerable customers. We are seeking stakeholder and customer feedback on this proposed program, including on the types of support initiatives that should be considered and levels of support that should be provided.
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7.6 Potential future Green Unaccounted for Gas of gas initiatives There are currently no carbon neutral gases such as renewable hydrogen The following sections set out or biomethane injected into gas networks in Australia. potential future of gas initiatives Australia’s National Hydrogen Strategy specifically highlights the benefits we could incorporate into our of establishing a domestic market through the blending of renewable operating expenditure over the hydrogen into gas networks in growing the industry to increase scale and next AA period. lower costs. We have seem similar cost reductions with industry growth in Insights from our engagement renewable solar and battery technology. program show our customers see We could deliver emissions reductions by purchasing renewable or carbon lowering carbon emissions as very neutral gas in place of natural gas to replace our UAFG (as described important and expect us to pursue earlier, gas losses on our network). This would have the important benefit more opportunities to lower of commencing the transition to a renewable gas future. carbon emissions further. With this in mind, we are considering We are currently aware of one renewable gas/carbon neutral gas two additional projects – outlined (collectively referred to as green gas) production project in South Australia below and not currently included in addition to HyP SA, which could have the ability to provide part of our in the Draft Plan expenditure and UAFG over the upcoming five-year planning period – being the Edinburgh price profile. These projects will Park bioenergy project. However, it is likely that more renewable gas help to drive the green gas sector projects will commence over the course of the next AA period. further, with a view to delivering Engagement to date indicates interest interest in pursuing projects to lowest cost decarbonisation to lower carbon emissions – UAFG is one means we can do this directly. customers. Whilst we would negotiate to purchase renewable gas at the lowest cost, In addition to driving it could be at a premium to natural gas given the infancy of the market. decarbonisation, these projects We are seeking guidance from our customers and stakeholders as to have the additional benefit of whether there is interest in AGN further pursuing this opportunity – positioning South Australia as a sourcing renewable or carbon neutral gas to replace UAFG, with a view to leader in green gas, building on lowering carbon emissions and supporting the emerging renewable gas the first mover advantage industry. delivered by the South Australian government when they were the We estimate the additional cost of sourcing 20% of our UAFG with carbon first state to release a hydrogen neutral gas would add around $1.50 to the annual gas bill of our roadmap in 2017. customers. We are therefore seeking to understand whether our customers are supportive of this initiative. As a leader in green gas, South Australia would be well placed to It is noteworthy that because the price of our UAFG is a cost-pass- benefit from the associated jobs through, customers would only pay more if and when AGN was able to and economic growth that a new source and supply renewable gas supply. industry could deliver. We are seeking stakeholder and customer feedback on these initiatives.
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Community Education Centre
The National Hydrogen Strategy supports the need for further community engagement, with an action to “Support best practice for community engagement and its use to build community awareness and ensure community engagement for large or significant projects.” We are committed to continuing to engage with stakeholders and the community on green gas. We currently do this through stakeholder meetings, conferences, community events and our website. Our engagement activities and external studies indicate that there is relatively little knowledge of green gas and a desire from the community to know more. With this in mind, and leveraging off of our HyP SA facility, there is an opportunity to develop a green gas stakeholder and community centre. Located at the Tonsley Innovation District, alongside our HyP SA facility, the Community Education Centre could include meeting and engagement spaces as well as information displays on hydrogen, biogas, natural gas, gas safety and gas appliances. It could also be the initiation point for tours of HyP SA. The centre would be a place to hold stakeholder and government meetings. The centre will also be a place where the community could come to learn more about the future of gas and which would run education programs, including regional programs, for primary school aged children on renewable fuels and gas safety. In the future the Community Education Centre could be expanded to include training facilities for plumbers and engineers. We estimate the additional cost of developing and running a Community Education Centre would add around $1.50 to the annual gas bill of our customers. We are therefore seeking to understand whether our customers would be supportive of this initiative and, if so, what aspects of a Community Education Centre are most important to them.
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7.7 Summary
Our $354 million opex forecast for the next AA period is slightly higher than the opex we expect to incur in the current AA period, once the effects of our proposed change in capitalisation policy is removed. Our customers will therefore continue to benefit from the opex savings we have achieved over the last two AA periods. Our opex forecast will also ensure that we: maintain our strong safety, reliability and service performance; have a healthy, engaged and skilled workforce; and
are sustainably cost efficient into the future. We are also seeking customer and stakeholder feedback on two future of gas initiatives which we could undertake in the next AA period.
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Our capex forecast is in line with current Capital levels and will ensure we maintain our strong expenditure safety, reliability and service performance
The capex we incur is ($30 million) lower than what we required to ensure gas is expect to incur in the current AA IN THIS CHAPTER: period (see Table 8.1). supplied in a safe and Investing $579 million in reliable manner and to More specifically, our expenditure on growth and customer service the next AA period, which support network growth is 5% lower than current are both expected to decrease, and customer service levels. driven by our extension to Mount Consistent with prior AA reviews, Barker in the current period, and Replacing around 860 km our capex forecast has been a smaller meter replacement of old cast iron, other low determined using a bottom-up program. pressure and early approach, with separate forecasts The following sections provide generation plastic mains. developed for our proposed further detail on the regulatory expenditure on activities that will Growing our network by requirements, the forecasting maintain: method we have used and our connecting around 43,000 capex forecasts for the next AA new customers. public safety and service reliability; period. This chapter also provides an overview of how we have network growth; and performed in the current AA customer service. period and how we ensure the capex we incur is both prudent The application of the bottom-up and efficient. approach has been informed by our Asset Management Plan All numbers quoted in this section (AMP), risk management are expressed in 2020/21 dollars framework, regulatory obligations including overheads and and projected network growth. escalation, unless otherwise stated. Our capex is forecast to be around $579 million in the next AA period, which is 5%
Table 8.1: Actual and forecast capex by priority ($million, 2020/21) Priority Current AA Next AA Drivers for change period period
Safety and 375.5 387.4 Start modification of reliability transmission pipelines to allow inline inspection (ILI) Lower mains replacement program
Growing the 194.1 159.9 Proposed Mount Barker network extension in 2020/21
Customer 40.3 32.1 Reduction in the number of service periodic meter changes required 609.8 579.4
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participants in customer 8.1 Regulatory Engagement insights framework workshops. Customers were supportive of our investment Customers expect a high level approach to maintain current Our AA proposal must include: of public safety and feel that levels of reliability and safety. the forecast capex for the safety is currently well next AA period; and Customers expect timely customer managed. service by knowledgeable staff Customers highly value an the capex incurred (or who demonstrate empathy and uninterrupted supply of gas in forecast to be incurred) in the understanding in responding to their homes and businesses current AA period. queries or resolving issues. and are satisfied with current Our forecast capex must reflect Customers and stakeholders are levels satisfied with our current that required by a prudent gas Customers and stakeholders customer service levels, but distributor, acting efficiently and support a proposed approach expect that digital communication in accordance with good industry to maintaining current levels channels will become increasingly practice to achieve the lowest of safety reliability. sustainable cost of providing available. We are proposing to Customers and stakeholders Reference Services to our invest in IT projects to improve are satisfied with current customers. online services for customers. This has been prepared in consultation customer service levels, with Forecast capex must also satisfy with customers with a focus on preference for interacting various additional criteria, web based services to keep costs with customers through a including to: low. variety of digital channels. Stakeholders have supported maintain and improve safety; We have developed our capex our approach to preparing our proposal in consultation with maintain integrity; operating expenditure stakeholders. We presented our proposals in the development comply with our obligations; draft capex proposal to both of this Draft Plan. meet demand on the reference groups in August and networks; October 2019 and included our mains replacement program, our result in an overall economic IT expenditure forecast, network benefit; or augmentation and customer where additional revenue growth. generated exceeds the Stakeholders were supportive of associated costs. how we have developed our capex Any forecast or estimate we proposal. They were also keen to provide must also be arrived at on understand that our costs are a reasonable basis and represent efficient. We have demonstrated the best forecast or estimate this in section 8.7 of this Chapter. possible in the circumstances.
8.2 Customer and stakeholder engagement
Customers told us their top priorities are price/affordability, reliability of supply, and maintaining public safety. Customers highly value our track record of performance for both reliability and public safety and expect this to continue. We shared our proposed mains replacement program with
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8.3 Our capex over time
Our capex is driven by our safety and environmental obligations, the requirements and expectations of our customers and the age, performance and condition of our assets. Figure 8.1 shows our actual and forecast capex over the current and next AA period. In particular our mains replacement program continues into the next AA period where we are forecasting a marginal decline in capex compared to what we are currently spending. The spike in the last year of the current period (2020/21) is due to the proposed extension to Mount Barker (8.9.6) and delays in two IT projects (GIS and mobility, 8.9.5)
Figure 8.1: 10-year capex
$200 $180 $612 million $160 $140 $120 $100 $80 $610 million $60 $579 million $40
Capex 2020/21)($million,Capex $20 Current AA Period Next AA Period $0 2016/17 2017/18 2018/19 2019/20 2020/21 2021/22 2022/23 2023/24 2024/25 2025/26 Actual Allowance Forecast
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8.4 How we develop Figure 8.2: Summary of capex planning process our capex forecast
Our capex forecast for the next AA period has been developed using a bottom-up approach, with the cost of undertaking each project estimated separately. This section describes how we develop the key elements of our capex forecast, being the proposed activities and forecast costs, in more detail. the costs of the options and the Services – new homes, consistency of the selected option 8.4.1 Determining our multi-user sites, existing with the relevant provisions in the homes and I&C customers; investment NGR. Lower ranked projects, on and priorities the other hand, are deferred. Meters – new domestic and Some of our forecast reflects the I&C customers’ meter continuation of existing programs 8.4.2 Forecasting connections; of work, such as our mains and efficient costs meter replacement programs. Meter Replacement – periodic Our forecast costs must be Others are new projects, such as meter change (PMC) efficient, reasonable and the modification of some of our (domestic and I&C meters); represent the best possible transmission pipelines to allow for and forecast or estimate in the ILI and digital customer service circumstances. Mains Replacement – general projects. block replacement of cast The process we use to identify the We have two categories for iron, unprotected steel and forecasting efficient capex costs to projects to be carried out is shown other materials (normal and ensure these requirements are in Figure 8.2. high-density areas), High- met. They are: Density Polyethylene (HDPE) As this figure shows, potential Unit rate categories, for high replacement (by class), multi- projects and program activities user service renewals, are identified by asset managers volume work with limited variation in scope (e.g. new piecemeal mains replacement having regard to our overarching connections) where the and inline camera inspections. Business Plans such as our AMP, risk management framework, forecast cost is based on a Unit rate prices are based on a unit rate price multiplied by regulatory obligations, projected range of information sources network growth and the full the volume of activity to be including: undertaken in the period; and lifecycle cost of distributing tender or contract information natural gas. Non-unit rate categories - low which has been tested The proposed projects are then volume, discrete projects - through a competitive market where the forecast cost is subject to review, risk ranking and process; built up based on the scope of phasing based on lifecycle cost, current actual rates or a deliverability and efficiency. work outlined within the project or program. historical average rate (i.e. Full business cases are then over the last three years of developed for the higher ranked The unit rate categories include: the current AA period) projects that are proposed to be Growth capex: achieved for similar work; and delivered within the regulatory both internal and external period. This allows a more Mains – new estates, existing homes and specialist engineering detailed assessment to be estimates. undertaken of the options to industrial and commercial address the identified problems, (I&C) customers;
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The non-unit rate categories We will continue integrity dig-ups and industrial customers to our include augmentation, IT, growth and surveys, and start modifying network. We will also augment to new areas, regulators and our higher-pressure transmission our network in both the north and valves, telemetry, other mains to allow ILI. We will replace the south extremities to support distribution and other non- end of life regulators, valves, the continued growth we have distribution projects and telemetry and cathodic protection seen in these areas and ensure programs. Each project or activity equipment, and continue to service levels are maintained for is supported by a business case. eliminate high risk meters located existing and new customers in in buildings and carports. We will these growing areas. Forecast costs for these works also invest in the ongoing may be based on tender or maintenance and upgrades of our contract information, current 8.5.3 Customer service core business systems to ensure actual or historical costs for similar they are current, fit-for-purpose, In the next AA period we propose works or specialist engineering resilient to cyber threats and to invest $32 million on projects estimates. continue to support the and programs to continue to meet requirements of our business the service expectations of our 8.5 Our capex efficiently. customers. This includes our priorities in the meter replacement program, which will replace ageing meters next AA period 8.5.2 Growing the to ensure accuracy of customer The key capex priorities in the network billing is maintained, and next AA period are: We propose to invest $160 million investment in our IT systems that support our customer service Safety and Reliability; in the next AA period on projects and programs that will grow our functions. We also plan to provide Growing the Network; and network. This includes laying more digital services and a greater variety of communication channels Customer Service. reticulation mains and services, and installing meters, to connect to bring us in line with industry As Figure 8.3 shows, 67% of our around 43,000 new residential forecast capex is focused on maintaining safety and reliability, Figure 8.3: Forecast capex by priority ($million, 2020/21) which are both top priorities for our customers. Customer 8.5.1 Safety and service, $32 , 5% reliability In the next AA period, we propose to invest $387 million on projects Growing and programs that will maintain the our strong public safety and network, reliability performance. The $160 , 28% largest of these is our mains replacement program where we will replace a further 860 km of old cast iron, unprotected steel Safety and and first-generation plastic pipes reliability, which are more susceptible to $387 , leaks, cracks and breaks. 67% By the end of the period we will have removed all remaining low pressure cast iron from our network. This achieves a very significant safety milestone and follows completion of the Adelaide CBD in the current period.
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standards and improve the service (HDPE 250) – a further 8.6.2 Meter experience for our customers. 13.5 km in addition to the Replacement 280 km we will have replaced 8.6 Capex drivers in in the current AA period; Customer meters measure the amount of gas delivered, which the next AA undertake inline camera forms a key component of each inspections and reinforcement period gas bill. We undertake periodic on 336 km of high-risk early meter changes to replace old The following sections provide generation plastic piping meters and ensure meter further detail on the capex drivers (HDPE 575) where possible, accuracy is maintained. Based on and activities we propose to and replace 295 km of high- the age and performance of our undertake in the next AA period. risk early generation plastic current fleet of meters, and the piping (HDPE 575) where The activities under each of these metering accuracy requirements inline camera inspection and areas are supported by our we must achieve, we forecast to reinforcement cannot be business plans and individual replace over 93,000 meters over completed. business cases. These business the next AA period at a total cost plans and business cases assess This totals 860 km of mains of $19 million. This is slightly the options considered to address replacement forecast for the next below what we are spending on the identified issue, the estimated AA period. periodic meter changes in the cost of each option, the untreated current AA period. We have used While this is a lower volume than and residual risk each option a consistent forecasting approach the 1,052 km we will complete in would result in and alignment with to determine the number of the current AA period, we are the capex requirements of the periodic meter changes required. forecasting a higher average cost NGR and our vision. across the program. This is due Individual business cases will form to: 8.6.3 Augmentation part of our Final Plan submitted to new external requirements We are always monitoring the the AER in July 2020. (such as the requirements of pressure and performance of our other utilities when network. As the number of 8.6.1 Mains undertaking work near their connections to our network grows, replacement assets) which have introduced we can see a deterioration in additional costs to our mains pressure and performance. We Our mains replacement program replacement activities; and use this information to determine remains a key focus in the next areas where our network is the fact we are replacing a AA period. It is the single most becoming constrained and larger proportion of smaller important activity we undertake to requires augmentation. diameter HDPE mains, which ensure public safety. Augmentation supports the requires direct laying of the We will invest $292 million to: continued growth of the network new pipe, compared to the and ensures service levels are complete the replacement of lower cost technique of pipe all remaining low-pressure insertion used more Figure 8.4: Installation of transmission cast iron, unprotected steel consistently in the past. This and other mains – a further is because we are able to steel pipeline, Morphett Rd, Oaklands 551 km in addition to the 345 insert a smaller diameter poly Park, December 2018 km we will have replaced in pipe into our larger cast iron the current AA period. All low and unprotected steel mains and medium pressure cast without reducing capacity (i.e. iron and unprotected steel by increasing pressure). mains will be removed from However, this is not possible the network by the end of the with smaller diameter HDPE next AA period which as these already run at higher represents a significant safety pressures. milestone;
complete the replacement of all remaining high-risk early generation plastic piping
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maintained for existing customers applications to ensure they 8.6.6 Growth in growing areas. remain current, fit-for- purpose and resilient to cyber We extend our network and lay We are seeing continuing strong threats; new reticulation mains, services growth in the north and south of and install meters to connect new our network and forecast two $8 million in rationalising our customers to our network where it augmentation projects will be IT applications and is economically and commercially required in the next AA period. infrastructure across AGIG; viable. In the north we will invest $2 million on an Asset We will invest $149 million to $8 million to build a new high- Investment Planning Tool connect around 43,000 new pressure main and gate station in which will allow us to residential and business Gawler. This will provide a new incorporate a broader range customers over the next AA connection into the SEA Gas of information sources into period. This includes new homes transmission pipeline increasing scenario planning and and businesses in greenfield and the capacity of the northern investment decision making; in-fill developments (including network to support continued and extension of our network to growth in the area. $5 million to deliver more Concordia residential estate and In the south we will invest customer services digitally in Kingsford Smith industrial estate $3 million to duplicate our high- line with those provided by in outer northern Adelaide), as pressure main between Seaford other businesses and the well as existing homes and and Aldinga providing increased expectations of our businesses connecting to our capacity for the growing southern customers. network for the first time. This metro network. This follows on includes connecting customers for from supply to McLaren Vale in the first time in Mount Barker. 2016, a high-pressure extension in 2017 and a transmission extension and new regulator in 2018. Figure 8.5: Capex by driver over the next AA period ($million, 2020/21)
8.6.4 Telemetry $4 , 1% Telemetry allows for the monitoring and control of our $68 , 12% network remotely through information captured from and transferred to equipment in the field. In the next AA period we will invest $2 million to replace end of life Supervisory Control and Data Acquisition (SCADA) equipment and install additional pressure $149 , $292 , 26% monitoring points to ensure we 50% can continue to collect appropriate pressure information from the network as it grows and changes.
8.6.5 IT System $34 , Our IT systems support several 6% core functions including billing, finance, asset management, asset $2 , 0% operations, regulatory reporting $11 , 2% $19 , 3% and customer service. In the next AA period we will invest: Mains Replacement Meter Replacement $18 million in maintaining and Augmentation Telemetry upgrading our current IT Growth Assets Other Distribution System Other Non-Distribution System
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8.6.7 Other distribution noted above, a significant regulatory obligations are met and proportion of our capex in the that our service performance is system assets next AA period is accounted for by maintained in line with our vision. We will invest $68 million on other our mains replacement program Many of these are approved by distribution system assets. The (50%) and the investment the Office of the Technical largest project for the next AA required to support the projected Regulator (OTR) and the Essential period is $35 million to start growth in the network (26%). Services Commission of South modifying our higher-pressure Australia (ESCOSA). The remainder is accounted for by transmission mains to allow inline projects and programs that will Our Safety, Reliability, inspection in accordance with ensure we continue to maintain Maintenance and Technical accepted good industry practice. our strong safety, reliability and Management Plan (Safety Plan) is We will also continue integrity dig- service performance. part of our overall approach to ups and surveys, replace end-of- system management. It follows a life regulators, valves, telemetry 8.7 How we deliver continuous improvement cycle of and cathodic protection capex efficiently Commit, Plan, Do, Check and Act, equipment, and continue to with the objectives of: eliminate high-risk meters located We operate within a framework of in buildings and carports. external and internal controls maintaining a strong focus on which govern the way we plan, safety and reliability in 8.6.8 Other non- assess, procure and deliver capital relation to the operation and works. This framework ensures management of our distribution we are making sound investment distribution network; system assets decisions for our customers, our ensuring suitable safety We will invest $4 million on other stakeholders and our business. management systems are in non-distribution system assets in Our operating context is place and operating to the next AA period. This includes summarised in Figure 8.6 below. effectively manage and keep replacement of small plant and risks associated with the equipment based on the age and 8.7.1 Key Business operation of our network to condition of these assets, as well Plans as low as reasonably as any changing business practicable; and requirements. We have a number of key business plans that govern the communicating relevant scope, timing and approach to information related to the 8.6.9 Summary of our undertaking investment/upgrade safe and reliable operation of capex forecast by of critical business information our distribution network with driver systems, asset replacement and our regulators. augmentation works that are Figure 8.5 provides a breakdown Our Asset Management Strategy necessary to ensure ongoing of our forecast capex by driver. As (AMS) and annual AMP are key network safety, that our
Figure 8.6: Summary of our operating context
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parts of our Asset Management plan and undertake asset integrity prior year spend and approved Framework. They outline our assessments to extend the regulatory allowances. We also asset management strategies remaining life, improve, replace, regularly review network which are consistent with good or where necessary, retire assets. performance, including through a industry practice. This ensures efficient, reliable and series of key performance safe operations of the network are measures as an input into our Subordinate to the AMS and AMP maintained. planning process. are: Our Delegation of Financial the Distribution Mains and 8.7.2 Financial Authority covers all financial Services Integrity Plan transactions within our (DMSIP) which outlines our governance organisation. It outlines the level approach to managing the Our business planning doesn’t of financial authority at each level integrity of our mains and stop with each AA period. We within our organisation. Only the services and provides the continually update our capex CEO has financial delegation to basis for the forecast plans to respond to changing approve funds for unbudgeted replacement of mains over business needs. initiatives, and only where it fits the next AA period; and A key part of our planning is the within the overall approved the Meter Replacement Plan approval of the capex budget by budget. This provides strong (also known as the Gas the Board each year. financial controls and governance Measurement Management in the delivery of capex. Plan in South Australia) which Once approved, projects are then details our compliance managed and monitored through 8.8 Our capex obligations and how this our capital delivery processes, this priorities in the drives the forecast volume of includes Executive Management meters to be replaced over Team review of key contracts current AA period the next AA period. before they are awarded. In total, we expect to invest $610 These business plans outline how We regularly report our million by the end of this AA we continually monitor, evaluate, expenditure performance against period. Like our capex proposal for the Figure 8.7: Current AA period capex by priority ($million, 2020/21) next AA period, our capex in this AA period aligns with our customers’ priorities of: Customer service, safety and reliability; $40 , 7% growing the network; and customer service. Figure 8.7 provides a breakdown of the amount of capex we expect Growing the to incur against each of these network, priorities. As this figure shows, $194 , 61% of our capex in the current 32% AA period is focused on safety and Safety and reliability, which together with reliability, price/affordability reflect the top $375 , priorities of our customers. 61% 8.8.1 Safety and Reliability At the end of the current AA period we will have invested $376 million (forecast to the end of the period) on projects and
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programs that will enable us to development in Bowden just north the current AA period, and as maintain our strong safety and west of the Adelaide CBD. outlined above will remain a key reliability performance. Furthermore, we have extended focus in the next AA period. It is our network to new residential the single most important activity We have replaced over 751 km of developments in Two Wells in we can undertake to ensure public old cast iron, unprotected steel Adelaide’s north. safety. and first-generation plastic pipes, with a further 307 km planned for In the current period, we will the next 18 months. We will 8.8.3 Customer service replace 345 km of old low- complete our mains replacement pressure cast-iron, unprotected We have invested $40 million program in the Adelaide CBD, steel and other mains, including (forecast by the end of the period) removing the extreme risk all 53 km remaining within the on projects and programs to associated with these mains as Adelaide CBD. These low-pressure deliver a service experience that agreed with the OTR. mains were identified as continues to meet the representing a high and extreme Completing the mains expectations of our customers. (in the case of the CBD) risk to replacement program in the This includes the replacement of public safety. As agreed with our Adelaide CBD represents a almost 150,000 meters under our technical regulator, the OTR, we significant safety milestone for our meter replacement program. are on track to complete the business. We are on track to replacement of 345 km of low deliver the full volume of mains 8.9 Capex drivers in pressure cast iron, unprotected replacement approved by the AER the current AA steel and other mains, including for the current AA period. period all old CBD mains by the end of We have undertaken integrity dig June 2021. This volume of activity ups and surveys, replaced end of The following sections provide is also aligned with our life regulators, valves, telemetry further detail on the capex drivers commitment to the AER in our last and cathodic protection and activities we have undertaken AA submission to replace a total equipment, and started to in the current AA period. of 351 km of these materials. eliminate high risk meters located We are also replacing early in buildings and carports. We have 8.9.1 Mains generation plastic pipes which also undertaken maintenance and have a history of cracks and upgrades of our core business replacement breaks. In the current period, we systems to ensure they are Our mains replacement program is will replace 280 km of HDPE 250 current, fit-for-purpose, resilient the largest driver of our capex in and 369 km of HDPE 575 mains, to cyber threats and continue to support the requirements of our Figure 8.8: Direct bury of new gas mains, Wakefield Street, Adelaide, August 2016 business efficiently.
8.8.2 Growing our network We have invested $194 million (forecast by the end of the period) on connecting almost 26,000 new residential and industrial customers to our network at the end of June 2019, with a further 12,000 expected for the last two years of the period. We have completed the first stage of planned augmentations in the southern metro network to support residential growth in Seaford, Aldinga and McLaren Vale, as well as network augmentation to support
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by the end of June 2021. This In the current AA period we have While expenditure in relation to aligns with our commitment to invested $7 million, including the the GIS and Mobility projects has replace a total of 664 km of these first stage of planned been delayed, we are planning to materials which was made to our augmentations in the southern complete the full scope of works, technical regulator, the OTR, and metro network to support at a lower cost than was the AER in our last AA submission. residential growth in Seaford, approved, by the end of June Aldinga and McLaren Vale and 2021. Further, we will complete inline upgrades to the Adelaide CBD camera inspections and eastern network. reinforcements on 250 km of 8.9.6 Growth HDPE 575 mains which have a In line with our vision of delivering diameter which supports this 8.9.4 Telemetry profitable growth, we will invest treatment. This will extend the life In the current AA period we will $187 million to connect around of these mains for an estimated invest a little under $1 million to 40,000 new residential and additional further ten years. replace end of life SCADA and business customers to our pressure monitoring equipment to distribution network over the 8.9.2 Meter ensure we can continue to current AA period. This includes Replacement effectively control and monitor our new homes and businesses in network remotely through greenfield developments close to We undertake periodic meter information captured from and our network, new homes and changes to replace older meters transferred to our assets in the businesses within our network and ensure meter accuracy is field. (infill), existing homes and maintained. Based on the age and businesses which are connecting performance of our current fleet 8.9.5 IT System to the gas network for the first of meters, and the metering time, and extensions of our accuracy requirements we must Our IT systems support a number network to: achieve, we have replaced around of core business functions McLaren Vale to the south of 107,000 meters to June 2019 and including billing, finance, asset Adelaide; forecast we will have replaced a management, asset operations, further 43,000 meters by the end regulatory reporting and customer Two Wells to the north of of June 2021 at a total cost of service. Adelaide; and $31 million over the five years. This is above our allowance of $24 In the current AA period we have Mount Barker to the east of million due to: invested a total of $38 million, Adelaide. which has been focused on a slightly higher number of nationalising and consolidating our 8.9.7 Other distribution replacements being required; major IT applications, leveraging and the capability of these systems system assets a higher actual unit rate cost through our application renewal We will invest $21 million on other incurred for domestic meter program and building our digital distribution system assets in the replacements driven by a capability. This is below our current AA period. This includes greater proportion of new approved allowance for the period completing integrity dig ups and compared to refurbished as we: surveys, replacing end-of-life meters required to be have been able to achieve a regulators, valves, telemetry and installed (where new meters “current minus one” version cathodic protection equipment, are more expensive than methodology for our and eliminating a number of high- refurbished meters). applications with less frequent risk meters located in buildings upgrades than what we had and carports. 8.9.3 Augmentation initially planned; and 8.9.8 Other non- We augment our network to were able to leverage the ensure we can support continued Business Intelligence platform distribution growth while also maintaining implemented by APA which system assets current service levels for existing means the infrastructure costs We will invest $3 million on other customers in growing areas. are spread over a larger base. non-distribution system assets in the current AA period. This
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includes replacement of small Figure 8.9: Capex in the current AA period by driver ($million, 2020/21) plant and equipment based on the age and condition of these assets, $21 , 3% as well as any changing business $3 , 1% requirements.
8.9.9 Summary of our capex in the current AA period by driver Figure 8.9 provides a breakdown $187 , 31% of our capex in this AA period by driver. As noted above, a significant proportion of our capex $322 , 53% in the next AA period is accounted for by our mains replacement program (53%), the investment required to support network growth (31%), our meter replacement program (5%) and $38 , 6% investment in IT (6%). $31 , The remainder is accounted for by 5% projects and programs that are $1 , 0% designed to ensure we continue to $7 , 1% maintain our strong safety, reliability and service performance.
Mains Replacement Meter Replacement Augmentation Telemetry IT Growth Assets Other Distribution System Other Non-Distribution System
Figure 8.10: (from left) Isolation and bypass on a live steel gas main, South Road, Hindmarsh, April 2017; Mains renewal isolation and cutting activities; Cut and capping low pressure cast iron main, Grote Street, Adelaide CBD, October 2016
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Table 8.2 below compares our For our largest single program – to lower volumes of meters capex in the current AA period mains replacement – we are required to be replaced. These with what we propose to incur in expecting lower expenditure in the declines are offset by an increase the next AA period by capex next period reflecting lower in other distribution system capex, driver. It shows that our proposed volume of mains replaced. We are driven by our transmission level of expenditure is consistent also projecting a decline in growth modifications for ILI project, as with what we expect to incur this capex reflecting the timing of the well as increases in our period. Mount Barker extension occurring augmentation, telemetry and this period as well as lower meter other non-distribution system replacement expenditure related capex.
Table 8.2: Forecast capex by driver ($ million, 2020/21)
Driver Current AA Next AA Key activities period period
Mains Replacement 321.7 292.4 Complete replacement of all low-pressure mains Complete camera inspections and reinforcement of first-generation polymer mains where possible and replace high risk mains which cannot be inspected by camera
Meter Replacement 30.7 18.6 Periodic replacement of end of life customer meters
Augmentation 7.4 11.0 Upgrades to the eastern Adelaide CBD network High pressure mains extension and then duplication in the southern metro network New gate station and high pressure main in the northern metro network
Telemetry 0.7 1.9 Replacement of end of life telemetry equipment Install small number of additional pressure monitoring
IT System 38.4 34.2 Maintain existing core business systems Deliver an enhanced digital customer service
Growth 186.7 148.9 Connect new residential and business customers to our network Extend the distribution network to new areas where it is commercially and economically viable to do so
Other distribution 21.0 68.0 Undertake integrity dig ups and repairs system Replace end of life valves, regulators and cathodic protection equipment Address high risk meters in building and carports Undertake overpressure risk reduction measures for I&C customers Start to modify transmission mains for inline inspection
Other non- 3.2 4.4 Replacement and repairs of small plant and equipment distribution system assets
Total 609.8 579.4
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8.10 Summary support the continued growth valves, over pressure risk in those areas and maintain reduction, cathodic protection Our capex in the next AA period reliability for existing and dig up repairs will ensure we: customers. ($33 million). maintain our high levels of Replacing end-of-life Replacing and refurbishing of public safety and reliability as telemetry equipment small plant and equipment expected by our customers; ($2 million) which is critical to ($4 million). operating and monitoring our connect new customers to our These projects and programs are network. network where it is broadly aligned to our track record commercially and Ensuring our IT systems are over the current period with our economically viable to do so; current and fit-for-purpose by forecast capex for the next AA and maintaining and undertaking period being $31 million below the regular upgrades of our actual forecast for this period. continue to provide the level current applications ($18 of customer service that our While mains replacement costs million), rationalising our customers require and expect. are lower because of a reduction applications and infrastructure in the kilometres to be replaced, The projects and programs we across AGIG ($8 million), and and growth to new areas is lower intend to deliver are described implementing new (related to our proposed Mount below. technologies for our business Barker extension in 2020/21), we and our customers where Continuing our mains are investing more in other there is an overall benefit or replacement program, distribution system capex to service improvement ($7 specifically we will; deliver our new transmission million). pipeline modification for the ILI complete the replacement Growing the network to new initiative which will enable of old cast iron, areas ($14 million) where it is conformance with accepted good unprotected steel and commercially and industry practice integrity other low-pressure pipes economically viable to do so, assessment for transmission (551 km, $165 million), and connecting over 43,000 pressure pipelines. representing another new residential and industrial significant safety milestone The projects and programs customers to our network for our customers and our outlined will deliver the high levels over the five years to June business; of public safety and reliability 2026 ($135 million). valued by our customers, grow continue replacing the Modifying our ageing our network (ultimately leading to highest risk, smaller transmission pipelines to lower prices for all of our diameter first generation allow for inline inspections customers) and ensure we plastic pipes (309 km, ($35 million) and other continue to provide customer $107 million); distribution system works service that meets the complete inline camera such as replacement of expectations of our customers. inspections across larger first generation plastic pipes (336 km, $9 million); and
renew 570 multi-user services ($7 million).
Continuing our meter replacement program ($19 million) to ensure accurate gas measurement and billing for our customers. Augmenting the southern and northern metropolitan networks ($11 million) to
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This chapter discusses the movements in our Capital Base capital base in the current and next AA periods.
IN THIS CHAPTER: We are required to to allow for our reasonable Our capital base reflects adjust our capital base needs for cash flow to cover the value of past for capex, depreciation our costs. investments that we have and inflation using 9.2 Customer and made in the network, but actual information over not yet recovered from our stakeholder the current AA period customers. engagement and forecast information We discussed our approach to over the next AA period. setting our capital base with our We estimate that the reference group members at our value of our capital base meetings in December 2019. at the end of the current Members were keen to period will be around understand how we are responding to the uncertainty $1.8 billion. around the future of the network 9.1 Regulatory given the ongoing decarbonisation of electricity supply alongside the Framework South Australian Government target to be carbon neutral by We are required to adjust our 2050. Members were interested to capital base to reflect capex (net of any amounts contributed by understand how the uncertain role of gas networks (and gas more our customers), inflation and depreciation. We are also generally) in a low carbon economy could affect their required to remove the value of economic life (and hence any assets that we have sold and depreciation). reflect the reuse of redundant assets in the current AA period. We recognise that there is some Our forecast of depreciation is uncertainty around future energy delivery models, however we required to be set: believe that it is too early to so that our prices vary over advance depreciation (or similar time in a way that promotes proposals) particularly given the efficient growth of the feasibility work currently services provided by our underway into renewable gases business (which services being injected into gas networks. were explained in Chapter Given this, we are applying the 6); methodology previously approved by the AER for our Victorian and so that our assets are Albury networks. This depreciated over their methodology takes into account economic life; the impact on depreciation of our to allow for changes in the mains replacement program. Our expected economic life of a stakeholders have indicated particular asset; support for this approach. so that an asset is depreciated only once; and
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9.3 Capital Base as at “funding adjustment” reflects an 9.4 Capital Base as at 1 July 2021 adjustment for the difference 30 June 2026 between the forecast and actual We have adjusted (or rolled- capex in the last year of the This section discusses the forecast forward) our capital base as at previous AA period (i.e. 2015/16). adjustments made to the capital 1 July 2016 with actual capex and Consistent with AER practice, the base over the next AA period. inflation and forecast depreciation adjustment reflects the return recovered by AGN that otherwise over the current AA period. We 9.4.1 Capital have used forecast information for would have occurred if actual 2019/20 and 2020/21 as actual information for 2015/16 were Expenditure information is not yet available. available. Our forecast capex was discussed Table 9.1 shows the adjustments The closing value of the capital in Chapter 8 of this Draft Plan and we have made to our capital base base forms the opening capital is reproduced in Table 9.2, with over the current AA period. The base for the next AA period. the capex allocated to the same
Table 9.1: Roll Forward of the Capital Base 2016/17 to 2020/21 ($nominal, million)
2016/17 2017/18 2018/19 2019/20 2020/21
Opening Capital Base 1,374.2 1,449.3 1,520.3 1,602.5 1,686.6
Less Depreciation 44.0 49.3 56.4 63.4 65.0
Plus Conforming Capex 95.8 99.0 109.6 118.9 156.1
Plus Actual Inflation 23.2 21.4 29.0 28.6 31.0
Less 2015/16 Capex Adjustments 0.0 0.0 0.0 0.0 11.6
Less Funding Adjustment 0.0 0.0 0.0 0.0 3.5
Closing Value 1,449.3 1,520.3 1,602.5 1,686.6 1,793.7
Note: Totals may not add due to rounding.
Table 9.2: Forecast Capex 2021/22 to 2025/26 ($nominal, million)
2021/22 2022/23 2023/24 2024/25 2025/26
Mains 77.0 81.7 73.2 66.6 65.4
Inlets 14.4 14.5 14.5 14.4 14.3
Meters 6.2 6.2 7.6 7.0 7.7
Telemetry 0.4 0.5 0.3 0.3 0.3
IT system 5.6 6.9 7.2 9.2 5.2
Other distribution system equipment 13.0 14.8 13.8 13.7 12.8
Other 0.9 0.9 0.9 0.9 0.9
Closing Value 117.5 125.6 117.5 112.1 106.6
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Table 9.3: Summary of Lives Used to Calculate Depreciation
Asset Category Standard Useful Life (years)
Mains 60
Inlets 60
Meters 15
Telemetry 20
IT system 5
Other distribution system equipment 40
Other 10
Table 9.4: Forecast Straight-line Depreciation, 2021/22 to 2025/26 ($nominal, million)
2021/22 2022/23 2023/24 2024/25 2025/26
Straight-line Depreciation 93.6 100.2 108.2 106.2 113.4
asset categories used to adjust We are also seeking to ensure later updated for actual inflation our capital base. We note that the that the value of the assets when adjusting the capital base capex rolled into the capital base removed from our network as part for the previous AA period. includes an amount equal to half a of the mains replacement program Forecast inflation is also used in year of return in the year the are fully depreciated by the end of determining the total revenue that capex is incurred (and is therefore the next AA period (see Section we can recover (and hence the not the same as our capex 9.3). This will ensure prices we can charge). This is forecast in Chapter 8). The AER intergenerational equity as future reflected in the methodology that makes this adjustment to account customers will not pay for assets the AER uses to determine our for the fact that we do not earn a that are no longer in use. This is total revenue, which relies on return on the capex within the consistent with the approach used inflation to determine the year it was spent. by the AER in the Victorian gas following two costs: reviews, and results in bringing 9.4.2 Forecast forward $215 million of Return on capital – which is Depreciation depreciation over the next AA calculated by multiplying a period. nominal rate of return (see We have continued to apply the Chapter 10) by the nominal asset lives that were approved by Table 9.4 shows our forecast capital base determined in the AER for the current AA period straight-line depreciation, which this section (where a (as shown in Table 9.3). includes the adjusted nominal value includes the depreciation. In determining forecast impact of inflation); and depreciation for the next AA Regulatory Depreciation – period, we have applied the ‘year- 9.4.3 Inflation which is calculated by by-year’ tracking approach. This Forecast inflation is a critical deducting from forecast approach is consistent with that element in determining our total straight-line depreciation used by the AER for other revenue and pricing. As explained (see Table 9.5) the forecast networks, including our AGN earlier, forecast inflation is used to inflation adjustment applied Victoria and Albury networks. adjust the capital base over the to the capital base. next AA period. This forecast is
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Table 9.5: Forecast Regulatory Depreciation, 2021/22 to 2025/26 ($nominal, million)
2021/22 2022/23 2023/24 2024/25 2025/26
Straight-line 93.6 100.2 108.2 106.2 113.4 Depreciation
Less Inflation 42.0 43.6 45.3 46.8 48.3
Regulatory 51.7 56.6 62.8 59.4 65.1 Depreciation
Table 9.6: Forecast Capital Base, 2021/22 to 2025/26 ($nominal, million)
2021/22 2022/23 2023/24 2024/25 2025/26
Opening Capital 1,793.7 1,862.8 1,937.8 2,001.6 2,065.6 Base
Less Depreciation 93.6 100.2 108.2 106.2 113.4
Plus Conforming 120.8 131.6 126.6 123.4 120.2 Capex
Plus Actual 42.0 43.6 45.3 46.8 48.3 Inflation
Closing Value 1,862.8 1,937.8 2,001.6 2,065.6 2,120.7
Note: Totals may not add due to rounding.
The AER removes inflation in should review its approach to approach, which relies on the determining regulatory estimating inflation. This is due to same market data to set the depreciation to essentially remove concerns raised by several allowed rate of return (see the additional compensation for businesses of the ongoing Chapter 10), has closely followed inflation in determining the return difference between forecast and actual inflation over the current on capital, which arises from actual inflation. AA period. multiplying a nominal rate of A potential alternative approach is The use of market data is return by a nominal capital base to use a market-based approach currently used by the Economic (referred to as a double count of to forecasting inflation. This Regulation Authority (ERA) in inflation). approach would rely on market Western Australia, the Office of As a result, an issue arises if there data using the difference between Gas and Electricity Markets is a significant divergence yields on nominal and indexed (Ofgem) in the UK, and was used between forecast and actual Commonwealth Government by the AER prior to 2008. While inflation. If forecast inflation is Bonds (referred to as the Bond we believe a change is warranted, over-estimated relative to actual Breakeven approach), as opposed in keeping with delivering a plan inflation, it has the effect of to the current approach which capable of being accepted we will decreasing rates of return below uses the mid-point of the RBA’s apply the AER’s current approach that determined by the AER (as target 2% to 3% band. to forecast inflation up until the AER decides otherwise. the adjustment to depreciation is Figure 9.1 shows actual inflation greater than it should be). This in- compared to both inflation as per turn means benchmark revenue is the Bond Breakeven approach and below efficient levels (see Section the estimate of inflation in the 9.3.4) AER’s recent decisions with We understand that the AER is respect to our South Australian currently considering whether it network. The Bond Breakeven
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9.4.4 Forecast This shows a closing capital base of $2,121 million as at 30 June Regulatory 2026 in nominal dollar terms. Depreciation 9.5 Summary Forecast regulatory depreciation is used to determine the total We have adjusted our capital base revenue that we can recover over over the current and next AA the next AA period. This is periods to reflect actual/forecast calculated as forecast straight-line capex, depreciation and inflation. depreciation that is used to adjust the capital base less the inflation We have adjusted depreciation to adjustment that is applied to the reflect the completion of our capital base. Table 9.5 shows mains replacement program over forecast regulatory depreciation the next AA period. This that is used to determine assumed adjustment is consistent with our total revenue for the next AA obligations and previous decisions period, which as explained has made by the AER. We have also been determined using the AER’s applied the AER’s approach to preferred approaches to forecast inflation, although we calculating both depreciation and remain concerned that this inflation. approach will continue to materially overstate actual inflation. 9.4.5 Forecast Capital
Base The forecast capital base over the next AA period, taking into account forecast depreciation, capex and inflation, is set out in Table 9.6.
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Our single largest cost relates to the cost of Financing financing our $1.8 billion investment in the South costs Australian natural gas distribution network.
In this Draft Plan, the is used to calculate the cost of tax IN THIS CHAPTER: allowed rate of return building block. Further guidance in respect of the cost of tax is also We have followed the and the cost of tax have provided in the AER’s December AER’s Rate of Return been calculated 2018 Tax Review. Guidelines to estimate the according to the AER’s rate of return. Rate of Return Guideline Based on forward market and the recent Tax estimates, the rate of Review. return is 4.72% (compared Achieving a reasonable rate of to 6.14% at the start of return is essential in order to the current period). attract the necessary funding from shareholders (through equity) and We are expecting lower debt providers to continue to financing costs in the next invest in our networks. We are AA period, with the return also required to estimate the cost on our investment falling of tax the business will incur over by $72 million. the next AA period. The transition underway in the energy sector is not without risks for gas networks – risks over and above those being faced by electricity networks. Yet gas and electricity networks receive effectively the same rate of return. In this light, the prices we propose represent exceptional value for our customers and the South Australian economy.
10.1 Regulatory Framework The NGR provides a framework for calculating the return on the projected capital base (rate of return). The AER’s Rate of Return Guideline details the approach we are required to follow for calculating the rate of return under the NGR. The instrument also outlines the AER’s methodology for calculating the value of imputation credits (gamma) to equity holders, which
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We have followed the AER’s invest in a well-diversified each “tranche” (equal to one- approach in respect of all aspects portfolio of risky assets (also tenth of the debt portion of our of our financing costs and tax assumed to be a 10-year RAB) being updated annually. allowances. term); and The return on debt for each Equity beta – which measures tranche is formed as a weighted 10.2 Financing Costs the sensitivity of a business’ average of A-rated debt indices returns relative to movements (two-thirds weight) and BBB-rated Our financing costs are in the overall market returns debt indices (one third weight). determined based on an estimate (systematic or market risk). The third-party indices that are of the return on equity and the used to provide the required debt We have applied the AER’s return on debt over the next AA information are provided by the foundation model from the 2018 period, which are together Reserve Bank of Australia, Rate of Return Guideline, which referred to as our rate of return Bloomberg and Thomson Reuters. results in a return on equity of and are discussed in this section. 4.69% over the next AA period Unlike the return on equity, the (see Table 10.1). return on debt is updated annually and, once calculated, the cost of 10.2.1 Return on Equity These values are indicative and debt for a given tranche remains were measured using January The return on equity reflects the in place for ten years. This 2020 information, which is the return required by shareholders to assumes that we refinance our most recent actual information invest in the network. Unlike the debt equally over a 10-year available prior to the release of return on debt, it is not possible period. to observe the return on equity this Draft Plan. We intend to use required by shareholders in the updated information in preparing Applying the AER’s Rate of Return market. This means that we are our Final Plan. Guideline yields a return on debt required to use financial models of 4.72%, which we have applied Table 10.1: Indicative return on equity and other market evidence to in this Draft Plan. inform an estimate of the return Parameters on equity required by 10.2.3 Rate of Return shareholders. Equity risk-free rate 1.03% The AER assumes that 60% of our The AER estimates the return on total financing costs relate to debt equity using a “foundation Beta 0.6 with the remaining 40% relating model”6, which requires the to equity. Applying these following three parameters to be Market Risk Premium 6.10% percentages to the return on estimated: Return on equity 4.69% equity (4.69%) and return on The risk free rate – which debt (4.73%) results in an overall measures the return an rate of return of 4.72% in the first investor would expect from an 10.2.2 Return on Debt year of the next AA period. This asset with no risk. It is rate of return declines each year estimated based on the The return on debt reflects the in the next AA period due to our interest rate on Australian interest rate required by debt application of the trailing average Commonwealth government holders on issued debt (or the cost of debt approach. bonds with a 10-year term, interest rate on our loans). Much measured over a 20-day like the return on equity, the averaging period prior to the return on debt can be thought to 10.3 Cost of Tax commencement of the AA comprise a base interest rate and We have reflected the outcomes period; a risk premium, in this case referred to as the debt risk of the AER’s December 2018 Tax Market risk premium (MRP) – premium (DRP). Review in this Draft Plan. Our cost which reflects the expected of tax building block is based on return over the risk-free rate The return on debt is measured as an assessment of our taxable that investors require to a 10 year trailing average, with income, the applicable corporate
6 The AER foundation model approach the Sharpe-Lintner Capital Asset is based solely on the application of Pricing Model (SL CAPM).
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tax rate and the value of applying in Australia. The value of AER gave effect to three key imputation credits (gamma) to imputation credits (or gamma), changes: equity holders. These matters are like tax depreciation, is a specific the use of maximum 20-year discussed in this section. input that is required to determine tax asset lives; the cost of tax. The result of following the AER’s the use of a diminishing value approach to tax is that our tax method (rather than a building block is zero for each 10.3.2 Value of straight-line method) to year of the next AA period. Imputation calculate tax depreciation Credits over those 20 years; and 10.3.1 Calculating the The value of imputation credits (or introducing the ‘actuals Cost of Tax gamma) is determined by informed approach’ to the calculating the product of: expensing of some forms of We have determined the cost of capex. The AER Tax Review tax as total revenue less opex, tax the proportion of imputation recommended that networks depreciation and interest expense; credits distributed (the reflect the approach they where: distribution rate); and adopt in their financial tax Total revenue – which is the the value of the distributed asset base for regulatory sum of all of our costs (or credits to investors (theta). purposes. building blocks) (see Chapter The value of imputation credits (or These changes, to the extent that 12); gamma) is 0.585 as determined in they were not previously used by Opex – which is a specific the AER’s 2018 Rate of Return AGN, apply to new assets only, as building block that is used to Guideline. tax law does not allow for determine total revenue (see retrospective changes to the The effect of gamma is to reduce Chapters 7 and 12); approach to calculating tax any tax allowance by 58.5%. depreciation. Tax depreciation – which is However gamma has no effect on based on the calculation of this Draft Plan because the AER’s the tax asset base in any tax depreciation approach results 10.3.4 Tax Asset Base particular year; and in a Net Tax Allowance of zero. The opening TAB of $886 million Interest expense – which is ($nominal) as at 1 July 2021 has determined by multiplying the 10.3.3 Tax Depreciation been adjusted for the same cost of debt by 60% of our forecast information used to capital base in each year, Our approach to determining tax adjust our capital base over the reflecting the debt funded depreciation in this Plan has next AA period (see Table 10.2). proportion of the total capital changed compared to our base. previous AAs. The corporate income tax rate is This change is a result of the set at 30% consistent with the AER’s Tax Review, in which the prevailing corporate tax rate Table 10.2: Roll forward of the tax asset base ($million, nominal)
2021/22 2022/23 2023/24 2024/25 2025/26
Opening tax asset base 939.6 961.1 982.1 986.3 981.9
Plus gross capex 120.2 131.5 125.9 123.0 119.6
Less tax depreciation 98.8 110.5 121.7 127.4 135.4
Closing tax asset base 961.1 982.1 986.3 981.9 966.2
Note: totals may not add due to rounding
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10.4 Summary
Our financing and tax costs Table 10.3: Indicative AER Rate of Return and Gamma collectively account for around 40% of our total costs. For the Parameters AGN Draft Plan purposes of this Draft Plan, we have applied the AER’s Rate of Return on Equity 4.69% Return Guideline and the AER’s Tax Review in determining our Return on Debt financing and tax costs. 4.73% This results in a rate of return of Overall Rate of Return 4.72% 4.72% (see Table 10.3) and a Net Tax Allowance of zero. Gamma 0.585
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Our incentive to seek out efficiencies and Incentives other performance improvements will be strengthened in the next AA period through the addition of two new incentive schemes. IN THIS CHAPTER: We propose to strengthen We support the use of period, we are also considering our incentives through the effective, outcome- the introduction of a network innovation scheme. While we introduction of a CESS. based incentive schemes consider there is merit in the We are also considering that promote the long- introduction of a customer service the introduction of a term interests of our incentive scheme we have chosen network innovation customers. not to pursue this on the basis scheme which we consider that our customer satisfaction Incentive schemes are often used scores are improving without such would deliver benefits to by regulators to: a scheme. our customers. strengthen a service The following sections provide provider’s incentive to further detail on regulatory continuously seek out requirements for the incentive efficiency and performance schemes, the feedback our improvements and share the customers and stakeholders have benefits with customers; provided and our proposed provide balanced incentives incentive schemes. between opex and capex so that the most efficient 11.1 Regulatory expenditure mix is chosen; framework
balance the incentives to A key objective of the regulatory pursue efficiencies and to framework is to promote efficient improve or maintain service investment in, operation and use quality; and of, gas distribution networks. provide an incentive to invest In keeping with this objective, the in innovation in areas that can NGR provides for gas networks to provide longer-term benefits have one or more incentive to customers. schemes apply to encourage the To date, the only incentive efficient provision of services. scheme that has applied to our The NGR also requires any South Australian network is the incentive mechanism to be opex efficiency benefit sharing consistent with the revenue and scheme (EBSS). We are proposing pricing principles, the most to maintain this scheme in the relevant of which is the principle next AA period. that a service provider should be We are also proposing to provided with effective incentives supplement the opex EBSS with a to promote: capex efficiency sharing scheme efficient investment in (or in (CESS). The CESS will strengthen connection with) the network; our incentive to seek out capex related efficiencies, while also the efficient provision of maintaining service standards and services; and the health of our network. the efficient use of the network. To further strengthen our incentives over the next AA
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11.2 Customer and 11.3 Opex EBSS 11.3.2 Where it is used
stakeholder Our South Australian network is In South Australia, we have had engagement currently subject to an opex EBSS an opex EBSS in place for three and we are proposing to continue AA periods. Over these periods, Price and affordability are the top to employ this incentive scheme in we have achieved over $22 million priorities for our customers and the next AA period. in ongoing efficiency stakeholders. Customers expect improvements, the benefits of that we keep prices low today, but Further detail on how the EBSS which have been (or will be in the also invest in a sustainable future. works, where it applies and the next AA period) passed through to benefits it has delivered our In workshops 87% of customers our customers. In fact we customers is provided below. told as that lowering carbon calculate the scheme has emissions was very important to delivered $282 million in benefits them. Further, there was support 11.3.1 How the opex to our customers since its for investment in innovation EBSS works introduction. projects, in particular initiatives An opex EBSS is also in place on which lower carbon emissions. The opex EBSS, which is a key element of our opex forecasting all other gas and electricity We discussed incentives and approach (see section 7.3),7 is distribution and transmission presented our proposed approach designed to provide us with a networks regulated by the AER. In to our reference groups in continuous incentive to pursue July 2019 Energy Networks December 2019. There was broad opex efficiency improvements in Australia published Rewarding support for our proposed any particular year of an AA Performance: How customers approach for a CESS and an period and to share any efficiency benefit from incentive-based Innovation Allowance generally. gains (or losses) with our regulation which calculated Customers expressed a desire to customers. customer benefits in the order of consider an innovation incentive in $3 billion delivered through the more detail before we submit our The EBSS operates in a symmetric operation of EBSS schemes Final Plan. manner, which means that we are applied to electricity and gas rewarded if there is an service providers in Australia incremental efficiency gain, and between 2006 and 2018. Engagement insights penalised if there is an Customers expect us to incremental efficiency loss. 11.4 Capex CESS pursue more opportunities to To ensure that we have an While we have had an opex EBSS lower carbon emissions incentive to pursue efficiency in place for a long period of time, further in addition to existing gains evenly throughout the AA we have not had an equivalent plans. period, we are able to retain the capex incentive scheme in place. Customers support benefit of any efficiency gain (or We are therefore proposing to investment in innovation incur the cost of any efficiency strengthen and balance our projects and are willing to loss) for five years. After the incentives by introducing a CESS. accept a small price increase relevant AA period, the benefit The form of our proposed CESS (cost) is passed through to our Stakeholders are keen to mirrors the ‘Contingent CESS’ that customers in the following AA ensure that our investments was recently approved by the AER period. are sustainably cost efficient. for our Victorian and Albury In effect, this scheme provides for networks. The AER has more
70% of the efficiency gains (or recently approved a CESS to apply losses) to be passed through to to Jemena Gas networks in New our customers in the form of South Wales for the 2020-2025 AA
lower (higher) prices and we period. retain the remaining 30%. The ‘Contingent CESS’ was introduced in Victoria following an extensive industry engagement program that included stakeholder
7 Our opex forecasting approach relies on actual incurred opex in the penultimate year of an AA period being efficient.
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representatives and gas reduce inefficient growth in distribution and transmission distributors at a national level, not our capital base by providing networks regulated by the AER. just Victoria. Further detail on how a greater incentive to incur this CESS works and where it efficient capex; and 11.5 Network currently applies is provided address the imbalance in innovation below. incentives that currently apply scheme to decisions regarding 11.4.1 How the CESS whether opex or capex should The current regulatory framework works be undertaken. makes it difficult to invest in Under the Contingent CESS, 70% innovation, even where it would: In a similar manner to the EBSS, of any incremental capex8 the CESS would provide us with a promote the efficient efficiency gains (or losses)9 we continuous incentive to pursue provision of services over the achieve would be passed on to capex related efficiency longer term; and/or our customers, subject to the improvements over the AA period following: enable other customer and to share any efficiency gains objectives to be met (e.g. to (or losses) with our customers. our ability to retain 30% of meet emissions targets and/or the efficiency gain would be The CESS would also: to support renewable energy contingent on us maintaining technologies). service standards and the health of the network, which This is because, as explained Box 11.1: Asset Performance Index would be measured using an above, the EBSS and CESS The API is used in the contingent Asset Performance Index provide incentives to reduce costs. CESS to determine how much of (API) (see Box 11.1); and In the absence of an innovation the efficiency gain we are able to scheme, this reduces the incentive retain. This metric reflects both: if we defer capex from one AA to spend on innovation, period to the next, the particularly where the payback service performance, as efficiency gain would be period on the investment is five or measured by the unplanned reduced. more years. We are therefore system average interruption considering whether or not to frequency index (SAIFI) and These elements of the CESS are introduce a network innovation unplanned system average designed to ensure that cost scheme in the next AA period. interruption duration index savings are achieved through Noting that there is a need for a (SAIDI); and efficiency improvements, not reduced service levels, or an whole of industry approach to the health of the network, as inefficient deferral of capex. innovation, we intend to work measured by number of through the scope of this scheme, reported leaks in gas mains, 11.4.2 Where it is used including whether it should be services and meters. introduced at all, with our As noted above, the AER has customers and stakeholders prior In our Victorian networks, the recently allowed a ‘Contingent to commencing industry wide AER set targets for each of these CESS’ to be applied to all gas engagement. measures based on the five-year distribution networks in Victoria historical performance of each and Jemena’s NSW gas network. If we meet or exceed distribution network although 11.5.1 How an these targets, we can retain some of the API measures differ innovation scheme 30% of the efficiency benefit. If, reflecting specific network could work however, we do not meet these characteristics. A form of the targets, the benefit can be CESS also applies to the electricity Network innovation schemes have reduced on a sliding scale, been used by regulators to potentially to zero (i.e. if we fall counter the lower incentive below 80% of the target). service providers have to invest in
8 The CESS applies to capex, net of contributions and disposals, and adjusts for material deferrals, the effect of ex post capex reviews and cost pass throughs. 9 These benefits and costs must be adjusted for any financing benefits or costs.
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innovation, relative to businesses original concept, technology therefore that a CSIS is not operating in competitive markets. or technique, not previously required to be applied for the next implemented that has the AA period. The lower incentive stems from potential to reduce the carbon the resetting of costs and prices at footprint of gas distributed by five-yearly intervals, which means our network; and/or a service provider may be unable to retain the innovation benefits have the potential to deliver for a sufficiently long period to net financial benefits and/or recover the investment. This is improvements in our services particularly the case where: to gas customers. the payback period for an While we intend to consult further investment is longer than the with our customers and AA period; and stakeholders on the form this scheme could take, we are an allowance for the currently considering a scheme investment is not included in that would allow up to $2.5 million the opex and/or capex per year to be dedicated in the allowance and an EBSS next AA period to innovation. To and/or CESS applies. put this into perspective, $2.5 To address this issue, some million translates to around $1 per regulators have provided service year on our average customer’s providers funding to undertake bill. eligible innovation based projects. If such a scheme is introduced we An example of such a scheme is will match any funding provided the Demand Management through the scheme, so that we Innovation Allowance Mechanism bear the same risk as our (DMIAM) that applies to electricity customers if the project fails. We networks regulated by the AER. will also ensure that the findings This scheme provides funding for are shared, to help the research, development and socialisation of benefits. implementation of eligible projects that have the potential to reduce 11.5.2 Where it is used the long-term cost of service A form of the network innovation provision. scheme, the Demand If we were to propose such a Management Innovation scheme for the next AA period, it Allowance Mechanism, currently would likely take a similar form to applies to electricity distribution the DMIAM. However, rather than networks regulated by the AER. A focusing on demand, it would network innovation scheme also focus on eligible projects that are applies to electricity, gas and designed to promote the efficient water businesses in the UK. provision of services over the 11.6 Customer service longer term by supporting: incentive scheme the decarbonisation of energy supply; and We had considered proposing the introduction of a Customer Service the movement to smarter gas Incentive Scheme (CSIS) for the networks. next AA period. However, we note To be an eligible project, the that our customer satisfaction proposed project would have to: scores – measured for nearly five years – continue to improve, involve the research, reflecting our ongoing focus on development, or our customers. Our conclusion is demonstration of a new or
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11.7 Summary
In the next AA period we are proposing to strengthen our incentives to pursue efficiencies and to share the benefits with our customers. We are proposing to supplement the existing opex EBSS with a CESS. We will also seek feedback from customers and stakeholders on a potential network innovation scheme before undertaking further and more detailed engagement on its design.
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Our customers’ overall demand for gas is Demand expected to fall in the next AA period, in Forecasts response to a range of external factors.
The demand for our efficiency and lower new IN THIS CHAPTER: services drives our dwellings growth; operations and is a key commercial customers to rise Our demand forecasts have by 0.2% per year, largely in determinant of our been independently response to higher projected determined applying prices. levels of economic activity in methodologies consistent Our forecasts of natural gas South Australia; and with those approved demand and customer numbers industrial customers to fall by previously by the AER are key inputs to our growth 1.3% per year, in response to consistent with past capex and opex forecasts. They higher wholesale gas prices. are also used to determine our trends. Overall, Core Energy projects that prices (reference tariffs), which the demand for gas by our Overall demand for gas in are calculated by dividing our customers will fall by 0.9% per the residential, commercial forecast revenue requirement by year in the next AA period. and industrial sectors is forecast demand. The following sections provide expected to fall consistent Reflecting the differences in the more detail on the relevant with past trends. nature of demand for our services, regulatory framework, the separate demand and customer forecasting method and the connection forecasts have been demand forecasts themselves. developed by independent expert Core Energy & Resources (‘Core 12.1 Regulatory Energy’), for our: framework Residential customers; Our AA proposal must include the Commercial customers forecast demand for reference (business customers who use services. In keeping with the NGR, less than 10 terajoules of gas these forecasts must: each year); and be arrived at on a reasonable Industrial customers (our basis; and largest business customers). represent the best forecast possible in the circumstances. These customer groups are consistent with our proposed The AER also identified a number Haulage Reference Services to be of principles of best practice for provided over the next AA period. demand forecasting in its 2013 Better Regulation program. The In the next AA period, Core AER concluded that forecasts Energy forecasts the total should: demand for natural gas for our: be accurate and unbiased; residential customers to fall by 1.0% per year, in response be transparent and to a range of external factors, repeatable; such as higher wholesale gas incorporate key drivers; prices, increasing penetration of solar energy, improved incorporate a suitable method appliance and dwelling of weather normalisation; and
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be subject to statistical model Energy has employed for our validation and testing. residential and commercial customers therefore discussed In previous AA reviews, the AER’s jointly below. consultants have assessed Core Energy’s forecasts against these principles and concluded that the Core Energy forecasts were consistent with the above principles. 12.2 Customer and stakeholder engagement
We engaged with stakeholders (including retailers and our customers) in respect of our demand forecasts. At our SA Reference Group meetings, Retailer Reference Group meetings, at one-on-one meetings with customers and through our large user survey we discussed the approach and the importance of understanding key drivers of future demand. Stakeholders indicated they understood our approach to forecasting residential, commercial and industrial demand and noted that the approach is consistent with that adopted for our recent reviews, including our last SA review. Stakeholders were comfortable with the approach to forecasting demand. In particular, retailers indicated that trends shown in demand forecasts are consistent with their own observations and expectations of demand.
12.3 Residential and Commercial Demand
The method that Core Energy has used to forecast demand and connections for the residential and commercial sectors is broadly the same, reflecting the fact they share the common key drivers of weather and gas price. The forecasting method that Core
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12.3.1 How our Further detail on some of the key approach that is used by AEMO, elements of this method is which is referred to as the forecasts were provided below. Effective Degree Day (EDD312) developed weather standard. This approach The method Core Energy has used Weather adjustment enables us to determine the volume impact attributable to to forecast our residential and Our residential and commercial annual variances to weather commercial customers’ demand is customers’ demand for gas is relative to the EDD baseline. summarised in Figure 12.1. strongly affected by weather, with The method depicted in Figure customers using more gas when it This volume impact is then 12.1 is consistent with the is colder to heat their homes and removed from the historic approach that was used to businesses and vice versa in consumption per connection trend develop the demand forecasts for warmer weather. An adjustment to derive a weather normalised the current AA period for both our for weather must therefore be trend that can be used for South Australian, and Victorian made to historic residential and forecasting purposes. and Albury networks, which were commercial demand to ensure the approved by the AER. It is also starting point and historic trends Energy prices used to forecast gas demand are consistent with the principles In addition to weather, our not unduly affected by abnormal employed by the Australian residential and commercial weather conditions (see Step Energy Market Operator (AEMO), customers’ demand for gas is when forecasting residential and 1(a)) in Figure 12.1. small commercial demand for its The adjustment Core Energy has Gas Statement of Opportunities. made is based on the same Figure 12.1: Forecasting method used for residential and commercial customers
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affected by changes in retail Figure 12.2: HIA actual and forecast dwelling commencements in South Australia gas and electricity prices. An 14,000 adjustment must therefore be Core Energy Forecast made to the historic growth in 12,000 consumption per connection to remove these effects (see Step 10,000 1(c)) in Figure 12.1. 8,000 An adjustment must then be made to the forecast demand 6,000 per connection to reflect the 4,000 forecast movement in retail gas and electricity prices. 2,000 To incorporate the effect of - these prices on both the historic 2008 2011 2014 2017 2020 2023 2026 data and forecast demand for Houses Multi-units Total Dwelling Commencements gas, estimates are required of: the responsiveness of gas Forecast new dwelling growth Residential connections demand to a change in retail The number of new residential Core Energy is projecting that our gas prices (referred to as connections expected over the residential connections (net of ‘own price elasticity’); and next AA period is directly related forecast disconnections)10 will the responsiveness of gas to the forecast number of new grow by 1.3% per year in the next demand to retail electricity dwellings in South Australia. AA period, reaching 484,822 by the end of the period (see Figure prices (referred to as ‘cross This aspect of Core Energy’s 12.3). price elasticity’). forecast is based on an The elasticity values Core Energy independent forecast of new The forecast growth in residential has assumed are the same as dwelling commencements by the connections is slightly lower than those used in our last AA, which Housing Industry Association the 10-year historic average are as follows: (HIA) (see Figure 12.2). growth rate of 1.6% per year. This is due in large part to: Own-price elasticity: a lagged As Figure 12.2 shows, HIA has long-term-own-price elasticity projected a decline in new lower forecast growth in new estimate of -0.30 for dwelling commencements, dwellings (see Figure 12.2); residential and -0.35 for particularly multi-unit dwellings, in a reduction in the number of commercial customers has 2018-19, and while it expects a projected electricity to gas been assumed. This implies small recovery in 2019/20, the connections; and that a 1% increase in retail number of new dwellings in gas prices will result in a 2021/22 is still expected to be a small increase in the 0.30% and 0.35% reduction below the peak observed in number of disconnections. in consumption per 2017/18. This lower forecast growth is connection for residential and largely driven by lower forecast commercial customers, 12.3.2 Residential economic activity and population respectively. demand forecast growth in South Australia over Cross-price elasticity: a long- Using the methodology set out the next AA period. term-cross-price elasticity of above, Core Energy has developed 0.10 has been assumed (this its forecast of residential demand implies that a 1% increase in in the next AA period by retail electricity prices will multiplying the forecast number of result in a 0.10% increase in residential connections by forecast consumption per connection). consumption per connection.
10 The forecast number of disconnections is based on the application of the 10-year historic disconnection rate to total connections.
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Consumption per connection Figure 12.3: Residential connections forecast (no.) 600,000 Core Energy is also projecting that Historic Actuals Estimate Forecast consumption per residential 500,000 connection will fall by around 2.3% over the next AA period, from 15.9 GJ in 2020/21 to 14.1 400,000 GJ in 2025/26. 300,000 As Figure 12.4 shows, this fall is consistent with the long-term decline in average residential 200,000 consumption per connection that has occurred in the last two AA 100,000 periods. It is also consistent with what has occurred across our - other distribution networks. 2009 2013 2017 2021 2025 The key drivers of this decline include improved appliance and Figure 12.4: Residential consumption per connection forecast (GJ) dwelling efficiency and the 25.0 substitution of gas appliances for Historic Actuals Estimate Forecast their electric equivalent (for example, substituting gas heating 20.0 for electric reverse cycle air- conditioning). It also reflects the expected increase in wholesale 15.0 gas prices over the period.
Total residential demand 10.0 Overall, the demand for gas by our residential customers in the 5.0 next AA period is expected to fall by 1.0% per year from 7,208TJ in 2021/22 to 6,849TJ in 2025/26 - (see Figure 12.5 and Table 12.1). 2009 2013 2017 2021 2025
This fall reflects the effect of the Figure 12.5: Total residential demand forecast (GJ) forecast decline in consumption per residential connection which is Historic Actuals Estimate Forecast partially offset by growth in 9,000,000 residential connections. 8,000,000
7,000,000
6,000,000
5,000,000
4,000,000
3,000,000
2,000,000
1,000,000
- 2009 2013 2017 2021 2025
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12.3.3 Commercial Figure 12.6: Commercial connections forecast (no.) 14,000 demand forecast Historic Actuals Estimate Forecast
Like residential demand, Core 12,000 Energy’s commercial demand forecast is calculated by 10,000 multiplying the forecast number of commercial connections by the 8,000 forecast consumption per commercial connection. 6,000 Commercial connections 4,000 In the next AA period, Core Energy is projecting the number 2,000 of commercial connections (net of disconnections) will grow by 1.1% - 2009 2013 2017 2021 2025 per year - lower than the historic trend due to slower forecast Figure 12.7: Commercial consumption per connection forecast (GJ) growth in GSP. 400.0 Historic Actuals Estimate Forecast Consumption per connection 350.0 In a similar manner to our residential customers, the average 300.0 consumption per commercial connection is expected to decline 250.0 in the next AA period, primarily as 200.0 a result of higher wholesale gas prices (see Figure 12.7). 150.0 The decline is not, however, 100.0 expected to be as pronounced as it is for our residential customers 50.0 due to the slower historic trend decline in consumption per - connection, with consumption per 2009 2013 2017 2021 2025 commercial customer forecast to fall by 0.9% per year over the Figure 12.8: Total commercial demand forecast (GJ) next AA period from 289 GJ in 4,000,000 2020/21 to 276 GJ in 2025/26. Historic Actuals Estimate Forecast Total Commercial demand 3,500,000
The total demand for gas from 3,000,000 commercial customers is expected to grow by 0.2% per year over 2,500,000 the next AA period, from 3,328TJ in 2021/22 to 3,359TJ in 2025/26 2,000,000 (see Figure 12.8 and Table 12.1). 1,500,000
1,000,000
500,000
- 2009 2013 2017 2021 2025
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12.4 Industrial as Maximum Daily Quantity period. In total 10 customers demand (MDQ)); and responded to the survey. the total amount of gas that For those customers that did not 12.4.1 How our forecast are our industrial customers respond to the survey, Core are expected to consume in a was developed Energy examined the relationship year (referred to as Annual between each customer’s historic In contrast to residential and Contract Quantities (ACQ)). commercial customers, our demand and economic activity. In those cases where there was a industrial customers are charged To help inform this forecast, Core statistically significant relationship, on the basis of the capacity they Energy conducted a survey of our the MDQ and ACQ was forecast by are expected to require on a day. top 25 industrial customers, the applying an adjustment to the The forecast demand for this objective of which was to better historic demand based on forecast group is therefore based on both: understand their future MDQ and economic growth. the maximum amount of ACQ requirements, including any planned connections or capacity that our industrial In those cases where there was disconnections over the next AA customers are expected to not a statistically significant require on a day (referred to relationship, the MDQ and ACQ were forecast by applying an Figure 12.9: Industrial Connections Forecast (no.) adjustment based on the historic Connections | No. trend. 140 The connections forecast for industrial customers has been 120 developed having regard to 100 historic growth estimates and information on known new 80 connections and disconnections.
60 12.4.2 Industrial demand 40 forecast
20 Industrial MDQ is forecast to decline by 0.84% per annum to - 53,361 GJ MDQ over the next AA 2010 2014 2018 2022 2026 period (see Figure 12.10). Industrial connections are also forecast to decline to 106 Figure 12.10: Industrial demand – MDQ (GJ) connections, from 113 at the start MDQ | GJ of the AA period. 80,000 12.5 Summary 70,000 Table 12.1 provides a summary of 60,000 our demand forecasts for the next
50,000 AA period. As this table shows, residential 40,000 and industrial demand is forecast 30,000 to decline over the next AA period whilst commercial demand is 20,000 forecast to rise.
10,000 Our demand forecasts are based on the methodology accepted by - the AER in the current AA period 2010 2014 2018 2022 2026 for both our South Australian, Victorian & Albury networks.
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Table 12.1: Summary of demand forecast
2021/22 2022/23 2023/24 2024/25 2025/26 Residential demand Connections (no.) 460,754 466,945 473,063 479,005 484,822 Consumption per connection (GJ) 15.5 15.1 14.8 14.4 14.1 Demand (TJ) 7,134 7,059 6,981 6,913 6,849 Commercial demand Connections (no.) 11,653 11,783 11,911 12,036 12,159 Consumption per connection (GJ) 286.3 283.6 280.8 278.3 276.3 Demand (TJ) 3,336 3,341 3,344 3,349 3,359 Industrial demand Connections (no.) 112 110 109 107 106 MDQ (TJ) 55,315 54,515 54,248 53,530 53,361 ACQ (TJ) 10,761 10,571 10,483 10,304 10,227
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This section sets out the total revenue and Revenue the proposed prices to apply over the next and Pricing AA period. Draft Plan we have had regard for the impact individual aspects of Our costs are referred to the plan will have on price. IN THIS CHAPTER: as ‘building blocks’ and As part of our engagement on this We have proposed to cut are summed to Draft Plan, we will also seek South Australian network determine total allowed feedback on our proposed pricing prices by 7.9% on 1 July revenue in each year of structure, specifically in relation to 2021 followed by increases the next AA period. the mix of fixed and variable of 1.2% each year components of our prices and our thereafter. We recover our costs proposed price path. This through the prices (or feedback will be reflected in our This will save the average Final Plan submitted to the AER by residential customer $30 tariffs) that we charge 1 July 2020. per year, commercial retailers for providing 13.3 Revenue customer $270 per year reference services. and industrial customer 13.1 Regulatory This Draft Plan outlines the basis $15,000 per year. of all the relevant building blocks Framework that are used to determine Our proposed price path building block total revenue. The We are required to determine reflects the forecast building block total revenue with total revenue for each year of the growth of our capital base and without the cost of providing next AA period as the sum of our Ancillary Reference Services which will enable revenue forecast opex, return on our (ARS) is provided in Table 13.1. growth commensurate capital base, depreciation of the with changes in our capital base and a forecast of the Our building block revenue is underlying costs. cost of tax. recovered through the prices we charge retailers for providing Our total revenue can also domestic, commercial and increase or decrease depending on our performance in relation to incentive mechanisms applying in the current AA period, such as the opex incentive mechanism (Efficiency Benefit Sharing Scheme – EBSS) which applies to our South Australian gas network. Our prices are required to reflect, to the extent possible, the underlying cost of providing services to our customers. 13.2 Customer and Stakeholder Engagement
Customers and stakeholders told us that affordability is their highest priority. In developing this
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Table 13.1: Building Block Total Revenue, 2021/22 to 2025/26 ($nominal, million)
2021/22 2022/23 2023/24 2024/25 2025/26
Return on Capital 84.6 87.8 91.4 94.4 97.4
Return of Capital 51.7 56.6 62.8 59.4 65.1
Opex 72.1 74.9 76.2 79.1 81.8
Incentive Mechanism 10.4 9.6 11.0 6.6 1.8
Cost of Tax 0.0 0.0 0.0 0.0 0.0
Building Block Total Revenue 218.8 229.0 241.4 239.4 246.1 (including ARS)
Less ARS 2.4 2.5 2.5 2.6 2.7
Building Block Total Revenue 216.3 226.6 238.8 236.8 243.4 (excluding ARS) Note: Totals may not add due to rounding
demand haulage services and to equate revenue (or ARS. We are required to set our building block revenue) with prices such that the total revenue our underlying costs we recover equals the building recovered through the prices block total revenue. The AER’s we charge retailers in 2025- Final Decision will provide for a 26 (the last year of the next series of price changes (or X- AA period) to ensure that factors) to ensure this objective is there is no one-off achieved. adjustment to prices (either The building block total revenue, positive or negative) required smoothed revenue and from 1 July 2026 to equate percentage changes in prices are smoothed revenue with costs. set out in Table 13.2. We have By aligning our price path to the developed our price path in order growth in our capital base we are to: more likely to sustain stable credit provide for revenue growth metrics at levels assumed by the that approximates the growth AER in setting the return on debt. in the capital base over the This is because our revenue will next AA period to ensure the more closely match our underlying growth in our revenue is costs over time (see Section commensurate with changes 13.3.1). in our underlying costs; and
Table 13.2: Proposed Price Path, 2021/22 to 2025/26 ($nominal, million)
2021/22 2022/23 2023/24 2024/25 2025/26
Building Block Total Revenue (excluding ARS) 216.3 226.6 238.8 236.8 243.4
Smoothed Revenue 217.8 224.8 232.1 239.7 247.9
Real Price Path -7.9% 1.2% 1.2% 1.2% 1.2%
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13.3.2 Financeability interest coverage a far easier business (that is, consumers are constraint to achieve). no better or worse off as a result The AER assumes a weighted of the adjustment over the We have assessed the key credit average of credit ratings between medium to longer term). A- and BBB+ when it sets the ratios delivered by our Draft Plan return on debt (as the assumed (see Table 13.3). Our Draft Plan credit rating directly impacts delivers an average FFO to debt of borrowing costs). We therefore 8.9% and FFO to interest of 2.9 consider it is good regulatory over the next AA period, which practice to consider whether our partially satisfies the thresholds proposal meets the credit metrics required for a weighted average required of A-/BBB+ rated A-/BBB+ rating. This reflects and business. supports our proposed price path shown in Table 13.2 above. The ratings agencies focus on the following two key credit metrics in If key aspects of this Draft Plan determining a credit rating for a are not accepted and these business: thresholds are not met, our view is that an adjustment to our cash Funds from Operations (FFO) flow would be required over the to debt – which is defined as next AA period to maintain the FFO divided by debt (and credit rating assumed by the AER which measures the in setting the return on debt availability of cash flow to (thereby ensuring that the plan repay the balance of for the next AA period is internally outstanding debt); and consistent). Such an adjustment FFO to interest – which is could include: defined as FFO plus interest varying the inflation divided by interest (and which adjustment that is used to measures the availability of calculate regulatory cash flow to pay interest depreciation, with the lower costs). inflation adjustment having FFO is calculated as total the effect of increasing smoothed revenue less interest, revenue (and hence cash opex and tax. Our conservative flow) in the next AA period; or view is that the ratings agencies shifting the classification of require a sustained FFO to debt capex to opex, which again ratio of at least 9% and a FFO to increases the cash flow given interest ratio above 2.5 to that opex is recovered in the determine a weighted average year it is incurred while capex credit rating of between A- and is recovered over the longer BBB+. We also consider that the term (up to 60 years). key focus of the credit rating agencies is on the FFO to debt Importantly, any such adjustment ratio given the prevailing very low alters the timing of cash flow interest rate environment (making rather than the total amount of cash flow recovered by our
Table 13.3: Draft Plan Key Credit Ratios, 2021/22 to 2025/26
2021/22 2022/23 2023/24 2024/25 2025/26 Average
FFO to Debt 9.5% 9.1% 8.9% 8.6% 8.4% 8.9%
FFO to Interest Cover 3.0 2.9 2.9 2.8 2.8 2.9
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Table 13.4: Charging Parameters by Customer Type
Residential (Tariff R) Commercial (Tariff C) Industrial (Tariff D)
Fixed Charge Fixed Charge 0 – 50 GJ MDQ 0-360 GJ 0-10 GJ 50-100 GJ MDQ 360-1,920 GJ 10-18 GJ 100-1000 GJ MDQ 1,920-6,000 GJ >18 GJ Additional GJ MDQ >6,000 GJ
13.5 Prices We currently recover approximately 75% of our As already noted, we recover our revenue in the residential and revenue through the prices that commercial segments in the we charge retailers for providing variable (volumetric) components reference services. This section of our tariffs and 25% through the outlines our current and proposed fixed components. This reflects pricing structures. previous stakeholder feedback supporting a high or very high 13.5.1 Current Pricing degree of variability in their gas Structure bill is preferred as it more closely reflects user based pricing. Our current pricing structure includes two zones, South Prices for our industrial customers Australia (excluding Tanunda) and are capacity based and consist of Tanunda. a number of banded charging parameters (in dollars per GJ of The South Australia (excluding MDQ) (see Table 13.4). All prices Tanunda) zone includes decline as usage increases to residential, commercial and promote better network industrial customers whilst the utilisation. Tanunda zone includes only residential and commercial customers. We are expecting to extend our network to Mount Barker in the next AA period. The tariff we will use will mirror the tariff applied in the Tanunda zone. We may rename the Tanunda zone to reflect the fact that there will be two residential pricing zones outside of the Adelaide metropolitan area included in the Tanunda zone. Prices for residential and commercial customers consist of a number of volumetric (or consumption) based charging parameters (in dollars per GJ per day) and a fixed supply charge (in dollars per day).
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13.5.3 Declining Block captures customers utilising gas AER in setting our cost of debt for space heating. allowance. Tariff Structure Given declining average gas We consider that it is good Both the residential and consumption, our tariff structure regulatory practice for the AER to commercial pricing bands (or is designed to encourage greater deliver a decision which delivers components) decrease as network utilisation. We consider sufficient cash flows to maintain customer usage increases (often our pricing structures align with the A- to BBB+ credit rating referred to as declining block our obligations that require AGN assumed by the AER in setting the tariffs). This pricing structure: to promote the efficient use of the return on debt to ensure the reflects the relatively low network. decision is internally consistent. marginal cost associated with We therefore consider there is We have performed this analysis increasing the supply of gas strong merit in retaining the and have concluded that the cash to a customer; and existing declining pricing structure flows under this Draft Plan are encourages greater network and propose that it be retained. sufficient to maintain the assumed utilisation by promoting credit rating, should it be largely connection of more gas 13.6 Summary accepted. appliances, which is part of We recover our costs, or building the package of measures that block revenue, through the prices we use to address the that we charge for providing observed long-term decline in network services. We have demand per connection (see proposed to cut our network Section 12). prices in South Australia by 7.9% For instance, our first residential (before inflation) on 1 July 2021 pricing band broadly captures a and increase prices thereafter by customer using a gas cooker and 1.2% per annum in line with the solar hot water system, the growth in our capital base. This second step captures a customer price path materially improves our with a non-solar gas hot water ability to maintain stable credit system while the final step metrics at levels assumed by the
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We are continuing the process of standardising Network our proposed terms and conditions.
Access Our reference service 14.2 Customer and terms and conditions set stakeholder the contractual engagement IN THIS CHAPTER: arrangements between Our terms and conditions have We propose to maintain AGN and network users. been subject to considerable the process of A key part of our relationship with stakeholder engagement through standardising our terms network users is a contractual a number of successive AA review and conditions across our agreement between the parties processes, and consequently, networks. that governs the conditions (or have been amended over time to terms) of access to our networks, take into account feedback we Our AA Document will commonly referred to as a have received from stakeholders remain consistent with the ‘Haulage Agreement’.11 The terms and decisions made by the AER. current period AA and conditions of the Haulage We have continued to apply Document. Agreement typically reflect the previous AER decisions as a base AER approved terms that are set for setting the proposed terms to out in our AA Document, unless apply to our network over the otherwise agreed by the parties. next AA period. The following sections outline the We have engaged further with processes followed to develop our retailers on the proposed terms to proposed terms of access to our apply to our South Australian South Australian gas distribution network leading into developing network over the next (2021/22 to our Draft Plan. This engagement 2025/26) AA period. has occurred primarily through our Retailer Reference Group We also describe the changes we (RRG), which comprises are proposing to the terms and representatives from retailers that conditions from those in place operate in South Australia. during the current (2015/16 to 2021/22) AA period. The terms AGN continues to set the and conditions are set out in our benchmark standard of AA Document, which will be consultation with industry in its AA provided alongside the Final Plan reviews. Furthermore, we support to be submitted to the AER by 1 AGN’s efforts to try and align the July 2021. terms and conditions of access for their SA AA with Victoria to the 14.1 Regulatory extent possible. Framework Red Energy and Lumo Energy Submission to our Proposed 12 We are required under the NGR General Terms and Conditions to specify the terms and conditions on which each 14.3 Approach reference service will be provided in our Final Plan. We commenced a process of standardising our terms across all jurisdictions where we have networks in 2012. Our five step
11 Network users are primarily gas 12 NGR 48(d)(ii)) retailers or self-contracting users of our networks.
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approach to engaging on our 14.4 Summary of the proposed terms and conditions is AA Document illustrated below in Figure 14.1. We believe there are a number of As noted earlier, the AA Document benefits to our customers from sets out the proposed prices and standardising terms of access as it terms and conditions under which promotes greater efficiency across we offer access to our networks. the industry and reduces The format of the proposed AA transaction costs. Document remains largely unchanged from the current AA Our approach to developing the Document. proposed Terms and Conditions includes: We are proposing the following changes to the AA Document: harmonising the proposed terms with the Victorian and Network Extensions and Albury Terms and Conditions Expansions, Capacity Trading, taking into consideration any Queuing and Changing jurisdictional differences Receipt and Delivery Points – requiring variation (being the changes to align with recent 13 most recent network terms changes to the NGR ; and approved by the AER); Speculative Capital incorporating common Expenditure – addition of amendments recently clause to align with our incorporated into South Victorian and Albury AA Australian Haulage Document. Agreements which will improve alignment and efficiency in the terms and conditions;
proposing a clause to share customer details. This is consistent with a clause in both the AusNet Services and Multinet Gas Access Arrangement Part C Terms and Conditions, which requires the User (Retailer) to provide telephone numbers and email addresses for each customer;
correcting typographical errors and anomalies; incorporating feedback from our RRG on the three drafts of our proposed Terms and Conditions; and
incorporating feedback from the Draft Plan on the proposed Terms and Conditions in preparing our Final Plan.
13 NGR 112
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Figure 14.1: Our engagement approach on Terms and Conditions
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14.5 Summary
The terms and conditions are a key part of our relationship with network users. The proposed terms are the basis that users gain access to our networks and generally form the basis for the contractual agreement entered into between the parties. Our proposed terms have gone through considerable consultation with stakeholders over the past seven years.
We consider that the process of standardising our terms across our networks is consistent with achieving lowest sustainable costs for our customers.
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Glossary
AA Access Arrangement HSE Health Safety Environment
ACQ Annual Contract Quantities HyP SA Hydrogen Park South Australia
AER Australian Energy Regulator I&C Industrial and Commercial (customers)
AGIG Australian Gas Infrastructure Group ILI In Line Inspection
AGN Australian Gas Networks KPI Key Performance Indicator
AHC Australian Hydrogen Centre LPG Liquid Petroleum Gas
AMP Asset Management Plan MDQ Maximum Daily Quantity
AMS Asset Management Strategy MFP Multifactor Productivity
ARENA Australian Renewable Energy Agency MGN Multinet Gas Networks
ARS Ancillary Reference Service MRP Market Risk Premium
capex Capital Expenditure Next 2021/22 to 2025/26 AA period
CBD Central Business District NGL National Gas Law
CSIRO Commonwealth Scientific and Industrial NGR National Gas Rules Research Organisation
Current 2016/17 to 2020/21 opex Operating Expenditure AA period
DBP Dampier Bunbury Pipeline OTR Office of the Technical Regulator
DCVG Direct Current Voltage Gradient PMC Periodic Meter Change
DP Delivery Point RBA Reserve Bank of Australia
DRP Debt Risk Premium RRG Retailer Reference Group
EBSS Efficiency Benefit Sharing Scheme SARG South Australian Reference Group
EDD Effective Degree Day SCADA Supervisory Control and Data Acquisition
ESCOSA Essential Services Commission of South SL Sharpe-Lintner Capital Asset Pricing Model Australia CAPM
FFO Funds from operations TAB Tax Asset Base
GDB Gas Distribution Business TFP Total Factor Productivity
GJ Gigajoule/s TJ Terajoule/s
GSP Gross State Product TRIFR Total Recordable Injury Frequency Rate (the number of total recordable injuries per million hours worked)
HDPE High-Density Polyethylene UAFG Unaccounted for Gas
HIA Housing Industry Association WPI Wage Price Index
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