How we’re leading it and what’s next Energy Networks’ Andrew Dillon on CYBER SECURITY
Ivor Frischknecht of ARENA talks DISTRIBUTED GENERATION
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The sector has seen a few major developments recently with progress on the National Energy Guarantee (NEG) taking a step forward after the COAG Energy Council agreed to progress to the final design stage.
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The industry has long advocated for a national energy policy to bring muchneeded stability to a sector undergoing so much change, and the NEG represents a viable step forward. While there are still questions to be answered, like many in the industry I’m looking forward to reading the final design when it’s released later this year.
We’ve also seen funding announced for several projects that are supporting the implementation of renewable energy, from new wind farm projects in NSW to Hydrogen Energy Supply Chain pilot projects in Victoria’s Latrobe Valley, and solar farms in Queensland.
In our conversations with the industry about the energy trilemma, two factors constantly come up as being critical to the solution – distributed generation and energy storage.
This edition takes a closer look at these topics, with ARENA’s Ivor Frischknecht exploring the impact of decentralised consumer energy assets, and what we can expect as the uptake of rooftop solar and batteries continues to increase. We’re also focusing on the huge influence that energy storage technologies are having on the grid and the way we think about electricity networks. There are a wide variety of storage projects currently in Australia, or planned for the future, from Tesla's Hornsdale Power Reserve battery, to Snowy Hydro pumped hydro, and the introduction of smaller companies with new technologies.
Energy magazine has continued its relationships with key industry associations, so in this issue you will find contributions from ARENA, Australian Energy Council, the Energy Policy Institute of Australia, Standards Australia, Energy Networks Australia, the Climate Council, AEMO, The Clean Energy Finance Corporation (CEFC), and companies like Snowy Hydro Limited, among other key players.
From within the industry we’ve also been contacted by a number of people with positive feedback about Issue One of Energy magazine. We’re excited to be able to fill a need for news and in-depth analysis of the most pressing issues in the energy industry, so please keep your thoughts and suggestions coming.
This issue will be distributed at events including the Australian Energy Storage Conference and Exhibition and Energy Networks 18, so I look forward to catching up with some of you in person to hear about how you have been taking advantage of current opportunities and keeping up with the sector’s rapid rate of change. Chris
Ivor Frischknecht was appointed inaugural CEO of ARENA in August 2012. Ivor is widely acknowledged as an expert and innovator in the rapidly evolving energy industry. He leads ARENA’s efforts to accelerate the commercialisation and integration of renewable energy into Australia’s energy system, as well as playing a leading role in transforming the electricity sector.
Ivor brings decades of private sector experience to ARENA, particularly involving smart investment in clean technology startups and growth companies. Before joining ARENA, Ivor was responsible for clean tech investments at venture capital firm, Starfish Ventures, which manages $400 million primarily on behalf of Australian superannuation funds.
Before that he was CEO and investor in the clean tech sector in Silicon Valley, California. Ivor has degrees in law and economics from the University of Sydney, and an MBA and Public Management Certificate from the Stanford University Graduate School of Business.
Chief
Sarah was appointed as the new CEO at the Australian Energy Council in March 2018, having worked as its General Manager of Corporate Affairs since January 2016. Sarah is a corporate and government relations professional with more than 10 years’ experience working with policy and regulatory frameworks across the resources and energy sectors. Previously, she was the Chief of Staff to the then Minister for Industry, the Hon Ian Macfarlane, and prior to that worked as a senior policy adviser to the Prime Minister (energy, resources, environment, agriculture and communications). Sarah has also worked for the industry – between 2008 and 2013 she worked in AGL’s Corporate Affairs team as Head of Government Affairs (and for some of that time also headed up its Community Engagement team). Sarah began her career as a corporate lawyer and has a Bachelor of Arts/Law from the University of Melbourne. She also worked as a policy adviser in the Howard Government.
Paul Broad was appointed Managing Director and Chief Executive Officer of Snowy Hydro Limited in July 2013. Before being appointed as a Director, Paul was Chief Executive Officer of Infrastructure NSW, AAPT, PowerTel, Energy Australia Sydney Water and Hunter Water.
Chief Executive Officer, Energy Networks Australia
Andrew Dillon is an experienced energy sector executive, most recently as the General Manager Corporate Affairs at AusNet Services, owners of electricity transmission and both gas and electricity distribution networks in Victoria.
Prior to AusNet, Andrew was General Manager Corporate Affairs at Energy Supply Association of Australia, worked in Corporate and Government Affairs at TRUenergy (now EnergyAustralia) and was a Senior Ministerial Adviser. He is also a Director of Goulburn Valley Water. Over two decades Andrew has worked in many parts of the energy industry as well as in government and consulting. He was appointed the Chief Executive Officer of Energy Networks Australia on 20 November 2017.
Ian Learmonth joined the CEFC as its CEO in May 2017, after previously serving as an independent member of the CEFC Executive Investment Committee. Ian has more than 25 years' experience as a financier and investor, working across clean energy and major infrastructure projects, as well as social impact investments.
He joined Social Ventures Australia (SVA) in 2011 to establish its Impact Investing business and raised SVA's first Social Impact fund in 2012. Ian structured and launched Australia's first Social Impact Bond and was also instrumental in establishing a dedicated Social and Affordable Housing fund with large super fund HESTA.
Previously an Executive Director of Macquarie Group for 12 years, Ian has investment banking experience in Sydney, Hong Kong and London. He established and led various businesses, notably European renewable energy and carbon credit investments, as well a cross-border structured finance and asset financing in Asia and Europe.
As NERA CEO, Miranda is a strategic leader at the forefront of innovation and collaboration within the Australian energy resources sector. It is a role she is passionate about, bringing together the country’s best minds from technology, research and enterprise, all with the aim of building a more sustainable and efficient energy resources sector.
With more than 20 years’ experience in strategic policy, risk management and stakeholder engagement, Miranda has a great understanding of the challenges being faced by the sector – one of the country’s biggest economic contributors and employers. Her interest in transformative and disruptive thinking, coupled with her significant industry experience, ensures NERA plays a vital role in leading the future of the energy resources sector. Miranda has overseen NERA since its inception in 2016 and prior to appointment as CEO, Miranda was the Director Environment, Safety & Operational Performance for APPEA, Australia’s peak oil and gas representative.
David Blowers has extensive experience developing both energy and broader public policy in both Australia and the UK.
He has spent the past three years as the Energy Fellow for the Grattan Institute, providing analysis and commentary on Australia’s electricity and gas markets, as well as on climate change policy. Prior to working for Grattan, he spent three years working on energy and earth resources policy for the Victorian State Government.
Megan is a Senior Executive with over 20 years’ experience in consulting, government, energy and water utilities, leading business strategy, growth and transformation. Prior to joining ERM Power in 2016, Megan was Director-General for the Queensland Department of Tourism, Major Events, Small Business and the Commonwealth Games. She has previously held senior executive positions in strategy and finance with Energex, United Energy and PricewaterhouseCoopers, and non-executive director roles on the boards of GOLDOC (the 2018 Commonwealth Games Organising Committee), Tourism and Events Queensland, Unity Water and Urbis.
As the CEO of CitySmart, Brisbane’s sustainability agency, Megan built the startup business and led it for six years. Megan is a member of Chief Executive Women and a former Telstra Queensland Business Woman of the Year, and named as an AFR 100 Women of Influence.
The COAG Energy Council has agreed to progress to the final design stage for the National Energy Guarantee (NEG), following the presentation of a detailed proposal by the Energy Security Board (ESB).
The ESB presented a high level design of the Guarantee to the COAG Energy Council on 20 April 2018 following a two month consultation process and the review of more than 150 submissions received from a broad range of groups and individuals.
The design of the NEG will now be finalised with the aim for it to be completed by the next COAG Energy Council meeting scheduled in August 2018.
Alongside the design document prepared by the ESB, the Commonwealth Government has prepared a document on the design elements that are its responsibility – setting the emissions target under the Guarantee, the treatment
of emissions-intensive trade-exposed industries and the role of external offsets.
Federal Minister for the Environment and Energy, Josh Frydenberg, said the decision by the COAG Energy Council was “a big step forward in delivering a more affordable and reliable energy system as we transition to a lower emissions future”.
“Backed by an unprecedented cross-section of business, industry and community groups, the Guarantee is a technology neutral energy policy that will drive the right investment in the right place and at the right time to secure Australia’s energy future,” Mr Frydenberg said.
“Modelling undertaken by the Energy Security Board (ESB) shows that wholesale electricity prices will decrease by 23 per cent under the Guarantee, flowing through to households and businesses.
“The Guarantee is only one element of the Turnbull Government’s comprehensive plan for a more affordable and reliable energy system. It complements practical actions such as our agreement with energy
ARENA will provide $370,000 in funding for a feasibility study into a ‘virtual microgrid’ for the Latrobe Valley. The $775,000 project will be led by Brooklyn-based energy company LO3 Energy and focuses on the feasibility of creating a ‘virtual microgrid’ across up to 200 dairy farms, over 100 household consumers and around 20 other commercial and industrial customers in the Gippsland region.
A ‘virtual microgrid’ is a local marketplace of connected energy users who can buy and sell electricity within a localised area.
The virtual microgrid will incorporate solar PV, battery storage, smart appliances and enabling technologies combined with the LO3 Exergy peer-to-peer energy trading platform which uses blockchain
technology to allow participants to securely buy and sell locally produced renewable energy.
This marketplace would allow Gippsland farmers to take greater control of their energy use, providing the opportunity to sell their solar power back to the grid, delivering savings on their energy bills.
Participants would be linked in an IoT-based marketplace while using AusNet’s distribution network. Participants would have a combination of solar, battery and smart devices to generate and store energy, and manage usage.
Farmers would be able to participate at no upfront cost through loans provided by the Sustainable Melbourne Fund, repaid through council rates.
The study is expected to be completed by the end of 2018, and if successful the pilot microgrid could be rolled out in Gippsland in 2019.
retailers to offer millions of customers a better deal on their power bill, new laws to stop the networks gaming the system and the work we have done to ensure more gas for the domestic market before it is shipped offshore.”
APPEA, the Australian Energy Council, the Clean Energy Council and the Energy Efficiency Council all welcomed the COAG Energy Council’s in-principle support for further consultation with stakeholders on the design of the National Energy Guarantee as a sensible way forward.
Energy Efficiency Council CEO, Luke Menzel, said the next several months will be critical as the detailed design of the NEG is hammered out.
“A strong pro or anti-NEG position is premature at this point as there is still so much detail to be worked through. What is positive is seeing Australia’s energy ministers engaged in a constructive process focused on resolving questions that have plagued policymakers for well over a decade.”
The project involves a consortium of partners including AusNet Services, Sustainable Melbourne Fund, Dairy Australia and Siemens.
ARENA CEO, Ivor Frischknecht, said the feasibility study would be the first step in transitioning one of Victoria’s primary agricultural regions towards renewables, and would be the first trial of a blockchainbased virtual microgrid in Australia.
“With significant increases in distributed energy resources across the network, there is an emerging opportunity to optimise these systems through orchestration.
“The ‘virtual microgrid’ concept brings an alternative approach to these solutions where the control remains with the customers, rather than retailers, who can choose to opt in depending on the current prices and energy types, or their willingness to provide demand response,” Mr Frischknecht said.
SGB MY Sdn Bhd is part of the SGB-SMIT Group of Companies in Germany, and commenced its production early 1996 in Nilai, Malaysia. The SGB Group of Companies is one of the world’s leading manufacturers of distribution, power and cast resin transformers, with 100 years of experience in manufacturing high-quality transformers.
SGB Malaysia manufactures:
• Oil distribution transformers up to 5,000 kVA
• Cast resin transformers up to 6,300 kVA
• Power transformers up to 50 MVA.
SGB MY plays an important role in the transformer industry, both in Malaysia and the export market within ASEAN, SAARC, Australia and the Middle East.
The Federal Government will invest $50 million into a world-first Hydrogen Energy Supply Chain (HESC) pilot project in Victoria’s Latrobe Valley.
The pilot project will turn brown coal into hydrogen as Australia continues to diversify its energy sources.
The pilot will create over 400 direct and indirect jobs, and is an initial step towards a commercial-scale hydrogen supply chain to diversify energy sources. Hydrogen energy is currently used in cars, electricity generation and industry.
The four-year joint federal, state and industry project will demonstrate the feasibility of turning brown coal from the abundant reserves in the Latrobe Valley into hydrogen to be exported to Japan.
A commercial HESC project has the potential to add more than $8 billion to Australia’s economy.
“We are not only creating a new industry and jobs in the Latrobe Valley and Port of Hastings, but building local skills in a future global hydrogen industry, estimated by the Hydrogen Council to be worth $2.5 trillion in 2050,” Prime Minister Malcolm Turnbull said.
“Our CSIRO hydrogen and energy experts will be working with their Japanese counterparts, maximising the exchange of scientific knowledge created from the pilot, including in carbon capture and storage.
Mr Turnbull said the project builds on the long-standing trade relationship between Japan and Australia on energy and resource commodities.
“Investing in this feasibility pilot is a down payment on our future economic
prosperity and security. We now embark on four critical, groundbreaking years.
“The world-first Hydrogen Energy Supply Chain pilot project is significant for the cutting-edge science and technology it uses, for the potential it represents for Australian industry in hydrogen production and export, and for the jobs it will create.”
The Australian and Victorian Governments are providing a combined $100 million in funding to the $496 million pilot project, co-funded by a Japanese consortium — led by Kawasaki Heavy Industries (KHI) — and the Japanese Government.
The project is being delivered by a consortium of large Japanese and Australian companies, including Kawasaki Heavy Industries, J-Power (Electric Power Development), Iwatani Corporation, Marubeni and AGL.
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Genex Power has signed a deal to secure the land option to develop a wind farm project up to 150MW as stage three of its Kidston Renewable Energy Hub in North Queensland.
Genex signed the binding heads of agreement with local landholders with the exclusive option to develop stage three of the project, with the new wind farm (K3-Wind) set to become the world’s first solar, wind and pumped storage hydro technology project.
The project is expected to benefit from naturally elevated topography along an escarpment of approximately 21km in length.
According to the company, the project area could be developed into a wind farm of up to 150MW, and connect into the National Electricity Market via the proposed new 275Kv transmissions line
at Kidston to be developed as part of its stage two project.
The K3-Wind Project represents the company’s fourth project in its development pipeline.
In combination with the existing stage one solar and planned stage two solar and hydro projects, the proposed K3-Wind Project could provide inversely correlated generation which could enable the dispatch of firm clean renewable electricity 24 hours a day, seven days a week.
Genex will now undertake a detailed feasibility study to assess and determine the technical and economic feasibility of constructing and operating a wind farm of up to 150MW at Kidston which will include a full assessment of the wind resource at the project site, transmission requirements, capital and operating costs, and firming up of anticipated capacity factors.
The Federal Government’s Cooperative Research Centres (CRC) program has received $90 million in funding to secure its research program until 2025.
The CRC program will be co-funding Future Fuels CRC with $26.25 million over its proposed seven year research program.
The Future Fuels CRC will undertake research and development to transition Australia’s energy infrastructure to a low-carbon economy using fuels such as hydrogen and biogas.
Collaborating with over 60 companies, six universities, the energy market operator and two regulators, the CRC will develop solutions for current infrastructure and equipment to use these new fuels today and well into the future.
Future low-carbon fuels offer the potential to store and deliver reliable,
clean and affordable energy through both new and repurposed equipment. The CRC will be researching across three integrated programs.
The first program will look into the future fuels technologies, systems and markets. It will address technical, policy and commercial barriers to the increased utilisation of future fuels and aims to accelerate development of production technologies and end use applications.
The second program will address the issues around safety and social acceptance of new and changed fuels, so industry can more effectively design, build and operate projects needed to deliver Australia’s energy needs now and in the future.
The final program focuses on the infrastructure itself. It studies the effect that future fuels introduction will have on existing and new infrastructure.
These programs are all supported by an extensive education and training program.
In addition to training up to 50
industry-ready PhDs, the CRC will deliver seminars, conferences and training for industry and the wider community.
NERA Chief Executive, Miranda Taylor, said additional investment in future fuels research and development is critical to ensure Australia successfully and sustainably transitions towards a lowcarbon economy.
“A decarbonised energy future cannot be achieved without supporting Australia’s traditional energy resources sector and leveraging Australia’s global competitive advantage, existing infrastructure, assets and technology into a smart, high value and sustainable domestic energy sector that can reliably meet Australia’s future energy needs."
Australia’s gas network businesses will contribute $8 million towards the venture, in addition to investing in trials that will demonstrate how hydrogen technology can be used in Australia’s existing gas networks. Research is expected to begin in July 2018.
The Albany Visitor Centre in Western Australia has been chosen as the location for the University of Western Australia’s (UWA) Wave Energy Research Centre, making it one step closer to becoming a global leader in marine renewable energy.
The announcement comes after the State Government awarded $3.75 million to UWA to establish a marine energy research hub in Albany to drive offshore research and innovation.
UWA Vice-Chancellor Professor, Dawn Freshwater, said the university was pleased to play a key role in the project and work with government and industry leaders to expand the state’s knowledge
of renewable wave energy.
“With our abundance of wave, wind and solar energy, Western Australia is ideally positioned to be at the forefront of renewable energy research and technology,” Ms Freshwater said.
“The Wave Energy Research Centre will undertake world-class research to support the growth of the entire marine renewable energy sector.
“Research will be undertaken across a range of areas including offshore engineering, oceanography, marine biology, marine planning and management with potential impact on marine policy and law, commerce and economics.”
The Wave Energy Research Centre will become ingrained in the Great Southern community and continue to work closely
with UWA’s Oceans Institute and industry partners to support the development of a wave energy industry in Albany and across WA.
“The university is already a global leader in offshore engineering with world-class geotechnical and hydrodynamic laboratory facilities at the Crawley campus,” Ms Freshwater said.
“By connecting these facilities to our Albany campus, we will be well placed to expand into a variety of marine research programs and to coordinate innovative research.”
State Government funding for the centre will be provided over four years and bring together more than 30 researchers from UWA.
AGL has committed to building a 252MW gasfired electricity generation plant to replace the Liddell Power Station.
The commitment represents an estimated investment of up to $400 million and would comprise flexible, fast-start generation capable of delivering rapidly dispatchable peaking and firming capacity into the National Electricity Market.
AGL is assessing sites for the project near AGL’s Newcastle Gas Storage Facility. This power station will consist of 14 reciprocating engine units capable of generating 18MW of capacity each. Construction on this project would be targeted to complete during the 2022 calendar year.
AGL Managing Director and CEO, Andy Vesey, said AGL is committed to supporting the orderly transition of Australia’s electricity generation capability to modern, clean and reliable energy supply.
“That’s why we gave seven years’ notice of when we intend to close the Liddell Power Station at the end of 2022, and we
are pleased to commit today to build the power station near Newcastle.
“AGL has now committed ahead of schedule to stage one of our NSW Generation Plan submitted to the Federal Government and the Australian Energy Market Operator (AEMO) in December 2017.
“In addition, we continue to assess the potential to develop a further 500MW of gas-fired generation capacity as part of stage two of that plan and are inviting commercial and industrial customers to provide their long-term demand commitments to enable AGL to progress this project.
“AEMO has confirmed that our plan addresses the capacity shortfall that may occur as a result of Liddell closing, and we remain committed to working with AEMO to deliver on that. This is in addition to our generation projects already under construction: 210MW of gas-fired generation in SA and, through the Powering Australian Renewables Fund, 653MW of wind farms in QLD and NSW.”
Mr Vesey said electricity generation is undergoing an increasingly rapid transition to lower-cost, clean energy, renewable and storage technologies. This requires the complementary development
of flexible, dispatchable gas-fired technology, as well as policies to support these developments.
“We are optimistic that the proposed National Energy Guarantee (NEG) will provide sufficient policy certainty to enable market participants such as AGL to invest with even greater confidence in cleaner, more reliable and more affordable energy generation.”
Stage one of the plan comprises projects required to meet AGL’s committed customer needs: the 252MW power station near Newcastle, a 100MW efficiency upgrade to AGL’s Bayswater Power Station, an agreement for AGL to offtake 300MW of solar capacity from Maoneng Australia’s Sunraysia solar project, the conversion of a Liddell turbine into a synchronous condenser, and up to 20MW of demand response capacity.
Stage two comprises projects required to meet AGL’s potential uncontracted commercial and industrial customer demand, and stage three involves further development that may be required if no other market participants invest in new generation prior to Liddell closing. Both stages two and three are subject to Board approval.
The Northern Territory Government has removed the moratorium on hydraulic fracturing, following an extensive, independent and robust 18-month inquiry which found the risks associated with unconventional gas development can be mitigated to acceptable levels or removed entirely.
The government has accepted the key finding of the Scientific Inquiry into Hydraulic Fracturing in the Northern Territory, that any risks associated with onshore gas development and hydraulic fracturing can be managed through effective regulation.
APPEA NT Director, Matthew Doman, welcomed the government’s decision but warned the manner and timeframe in which it implemented the inquiry’s 135 recommendations would be critical in determining the commercial viability of the industry.
“If they are to be implemented, they must be addressed within the next six months to ensure the industry can be on the ground exploring in the 2019 dry season,” Mr Doman said.
“Businesses, contractors and workers in the Territory are counting on the quick ramp up of the gas industry to get the Territory moving again. Explorers are ready to resume their activities as soon as the government gives the green light.”
Jemena also welcomed the announcement and intends to progress its plans to extend and expand the $800 million Northern Gas Pipeline (NGP).
This work is expected to create around 4,000 jobs across northern Australia, with early estimates placing the cost of the project at around $3–4 billion.
Jemena’s Managing Director, Paul Adams, commended the Territory Government’s decision, noting it had commissioned a thorough review into unconventional gas development that included broad and frequent consultation with the community. Mr Adams said the NGP will be completed in late 2018.
by Sarah McNamara, CEO, Australian Energy Council
Electricity is critical to our well-being and the functioning of a modern economy. The grid in Australia has been described as one of the biggest machines on earth. It is a machine that is going through an unprecedented level of change and as a result we are seeing the way that power is generated and delivered is changing quickly. The industry is facing both policy and investment challenges which must be either managed or resolved as a matter of urgency.
Akey driver of the investment challenge is the rolling series of closures of older coal-fired generation.
The Australian Energy Market Operator’s timeline of plants that are retiring or reaching 50 years of service (see Figure 1) illustrates the steady departure of coal generation plants from the National Electricity Market (NEM).
This capacity will be replaced by newer lower emissions technologies, including new large-scale renewable generation. What differentiates this generation is that it is not a like-for-like replacement. We will continue to need plants and technology that are dispatchable – or put another way, plants that can be turned on or that can increase output to balance supply and demand.
It will also require significant new investment. Exactly how much depends on a range of factors including technology costs, changes to carbon and energy policies, the timing when older plants retire and more.
Unsurprisingly, it gets more challenging to make a meaningful estimate the further into the future we look. The price of technologies, particularly renewables like wind and solar, have fallen quickly and made previous assumptions redundant. New coal is now more expensive per megawatt hour than new wind and solar, this is even after renewables have been backed up by technologies like peaking gas-fired power stations.
To get a better sense of the investment challenge, the Australian Energy Council recently commissioned Newgrange Consulting to look at the likely costs, as well as the possible mix of generation that we might see to 2030.
That report estimates that around $25 billion in investment will be needed to 2030. The largest proportion of investment is expected to go into new wind farms (51 per cent), followed by pumped hydro, large-scale solar and battery storage. The
remainder of the investment is expected to be made in solar thermal and gas-fired power plants.
These shares are predictions based on projections of relative technology costs assuming the market is allowed to choose the best way to meet customers’ need for reliable supply and the Commonwealth’s emissions target for the sector. If the market is distorted or policy settings remain uncertain, costs will be higher.
Additional investment is likely to be required to develop the transmission and distribution networks to deliver the electricity to homes and businesses. It is anticipated that substantial amounts will be spent by households and businesses on rooftop solar, battery storage and other distributed energy resources, and additional spending will be required to maintain existing electricity system assets.
Generation is more sensitive than other types of electricity infrastructure investment to the kind of stop-start policy that we have seen in Australia for more than a decade. The National Energy Guarantee is the sixth iteration of a proposed national energy policy.
It currently has the support of Federal and State governments, and the Energy Security Board appointed by those governments must now work through the detail of how the scheme would work in practice. That consultation will be concluded by August, at which point the Federal Minister will seek the support of the state and territory governments to proceed to implementation.
Industry is keen to see an end to the policy uncertainty of the past decade in order to stabilise investment signals. The uncertainty does not just impact higher carbon emitting forms of generation like coal-fired plants. The Newgrange report notes that the return on a renewable generator can also be affected by policy uncertainty, as it does not have clarity on the treatment of its competition, the more emissions intensive generators.
Where the new investment takes place is largely expected to be proportionally in line with current demand – except for South Australia, which is expected to attract more investment than its demand would suggest (because it is attractive to wind and solar investors) and Victoria which is expected to have less.
Unsurprisingly, 90 per cent of the new generation build will be in the NEM covering the eastern seaboard states, South Australia and Tasmania. The largest amount of new capacity will be in New South Wales, followed by Queensland and South Australia.
The expected capacity across the different states of the NEM and WA’s Wholesale Electricity Market (WEM)1 is 13,431MW as shown below (note the smaller grids in northern WA and NT were excluded).
The NEM is designed to balance supply and demand. The wholesale price indicates when supply is scarce and in this way works to encourage the development of new capacity to meet demand.
While there are still state-owned generators alongside private investors in the NEM, the market depends on attracting private investment capital. Private investors need confidence that they can achieve a return from their assets over the life of their investment.
The Newgrange report concludes that investment cannot be taken for granted, and that policymakers need to understand the value of stability to the sector. The industry will continue to advocate for a national energy policy to be put in place to deliver that much-needed stability and enable it to focus on the critical transformation of the sector that lies ahead.
¹ Source: Newgrange Consulting
by Robert Pritchard, Executive Director, Energy Policy Institute of Australia.
There is much community dismay at Australia’s failure to meet its power system needs. Intermittent, renewable power sources, such as wind and solar, have increased their share of the energy mix. However, governments are only beginning to understand the implications of this for energy policy.
The power system must be able to respond to changes in supply when the wind doesn’t blow or the sun doesn’t shine. Why? Because we have to keep the lights on, the schools open, the trains running and the factories operating. At the same time, we have to ensure that the power system remains affordable.
Keeping the lights on at an affordable cost requires a technology-neutral approach to energy policy – an approach that caters for all possible solutions without prejudice to, or predisposition against, any single option.
Technology neutrality must be embraced as the core principle of modern energy policy. There are two reasons for this: first, because it allows for the deployment of both intermittent and dispatchable power; and second, because it optimises the operation of the power system at the lowest possible cost.
Australia’s lack of energy policy certainty has two causes: the first is an insufficient understanding of power system technology; the second is excessive politicisation of the policy debate.
Decisions affecting the electricity sector, rather than being directed by a clear policy framework, have been made on an ad hoc basis in response to, and sometimes in ignorance of, a range of issues that are not so often spoken about, such as how we plan our cities as populations grow, what are the changing energy needs of our transportation and other infrastructure, and what new technologies are available to us.
More overtly, over the past ten years, the two main drivers of energy policy have been the increasing cost of electricity and, even more emphatically, environmental concerns over climate change.
Australian policy has now come to be driven by the risk of blackouts, a risk that is likely to continue as older coal-powered
stations are retired and the lost capacity is not replaced, potentially creating a cliff over which the entire power system could fall.
Policymakers have failed to provide an effective, apolitical mechanism for consideration of the energy mix and emissions reduction targets.
The major explanation for policy uncertainty has been the effective failure, for over a decade, of the Commonwealth and the states to articulate and debate the range of practicable, technology-neutral options for the energy mix for Australia, and to seek industry and community guidance.
One discussant at a recent Energy Policy Institute meeting quipped that technology-neutral in Australia means anything that doesn’t have nuclear or coal in it.
The Finkel Review of the Future Security of the National Electricity Market in 2016/2017 promised relief for a while. However, its fate and future direction is being mainly driven by the competing
interests of the Commonwealth and the states. The contrast might be made with a country like Japan, which regularly listens to industry and indicates to the market what new power generation infrastructure needs to be planned.
Policymakers have also failed to outline a truly technology-neutral approach to achieving Australia’s emission reduction targets.
To achieve significant reductions in emissions within the time-frame set by governments, and without also harming GDP, it will be necessary to continue relying for some time on natural gas and coal and to utilise carbon capture and storage technology. As well, there has been almost no discussion about the nuclear power option in Australia; either in public or in government.
There is increasing community frustration with governments about the lack of proper debate on technology options and inattention to the core principle of technology neutrality.
by Megan Houghton, Executive General Manager Energy Solutions, ERM Power
Big data is changing the way industries manage, analyse and leverage information, and is playing an increasingly important role in shaping the way businesses use and optimise their energy.
Data science can reshape the energy sector in the same way it is transforming financial services and health, where data scientists have built models for credit scoring and risk modelling and algorithms in the trading and medical fields for years.
Twenty years ago, no one would have predicted the reality of accessing financial advice from virtual robo-traders via our smartphones or using machine learning algorithms to detect and track health conditions like heart or respiratory disease.
Just as data science has transformed these sectors, it’s opening new doors in energy management in Australia right now.
Why is this so important?
With continued high energy costs a reality for businesses, along with the transition to renewables and locally generated and managed energy, what’s required is a fundamental shift in the way we think about and use energy, and, importantly, how we realise the potential of an avalanche of data being captured and delivered through multiple sources.
It’s widely acknowledged that the energy sector has been slow to recognise and harness the opportunity and power of data to transform business productivity and enhance customer value.
As a retail energy business, ERM Power has always been data rich and data driven. As the second largest retailer to commercial and industrial customers in Australia, we have a unique perspective on the needs of large energy users.
The increasing complexity of the industry and the proliferation of offerings and suppliers is challenging territory for businesses to navigate. Data can play a pivotal role in energy productivity by helping businesses make evidence-based decisions that can enable them to save money, reduce consumption, improve sustainability or generate revenue from their energy assets.
Data is core to determining the best energy management solutions and the right approach for a business’ sector, size and operations. There is a clear value in investing in data science and digital capabilities to stay ahead of the game.
Just as the health sector turned to data science models for diagnoses to solve health problems, the energy sector is increasingly using big data sets to diagnose the health of buildings and plants to solve their energy problems, in ways that consider the challenges and opportunities on both the supplyside and the demand-side of the energy equation.
An investment in big data and analytics can help businesses to make accurate, targeted and prioritised decisions around their energy productivity.
The amount of big data sets available from businesses own usage and those publicly available has grown exponentially with the Internet of Things. IoT’s ability to turn otherwise ‘dumb’ devices into digital intelligence, combined with faster WiFi and mobile networks and cheaper cloud-based storage options, is making the data science opportunity even bigger. In particular, IoT has the ability to deliver large amounts of real-time data, which has massive implications for the sector.
The utility sector is one of three sectors, alongside manufacturing and transportation, expected to spend the most on IoT worldwide in 2018, and this $73 billion spend will be dominated by smart grids for electricity, gas and water. A further
¹ The Internet of Things explained: what the IoT is, and where it’s going next. Zdnet.com
$92 billion is expected to be spent on cross-industry IoT areas like connected vehicles and smart buildings, air conditioning and security systems.1
Globally, the digitisation of the utility industry is occurring across the entire supply chain; through the network, via meters and into buildings, plants and equipment.
Real-time connectivity to what’s happening behind the meter is critical to enabling a data-led approach to energy management.
For example, with increasing deployment of ‘behind-themeter’ energy resources like renewable power systems, grid-synced generators, battery storage and automated demand management solutions, IoT devices can be used to collect data from these resources and combined with existing data sets from utility electricity meters and weather data and market data.
Data scientists can use these new combined data sets to build very rich and accurate data models that can predict the impact of proposed energy efficiency or demand management projects, both from an energy productivity and financial point of view. These models are particularly well suited to multi-site business environments, as they identify issues across the portfolio, then prioritise actions based on a financial business case.
They find the best prospects for each site, whether it’s solar, battery storage, power factor correction or another energy efficiency solution. They draw on data from historical use, meters, individual equipment and tariffs, as well as using external weather and solar radiance data for each site to forecast future energy consumption and costs.
ERM Power uses models like this to simulate different solutions over multiple time periods to work out the optimal combination from a cost and payback perspective, while also considering the impact of different tariffs and other efficiency measures for businesses.
As an example, demand flexibility, which relies on accurate, real-time data, is increasingly important for organisations driving an agenda of improved energy productivity. It enables organisations to reduce power consumption at different times when wholesale prices spike or there are constraints on the network. As the grid incorporates more renewable energy, modelling demand flexibility and taking action will be even more important.
Modelling and data visualisation are being used to create user friendly products like smart apps and dashboards that turn the otherwise complex energy data into something that’s simple, easily digestible and actionable. At ERM Power, design thinking methodology sits at the heart of new product development to ensure capabilities and tools are in line with user needs.
Using data science and machine learning technology, ERM Power has developed a predictive forecasting and notifications smart app. Relatively new to market, the ERM Power app can predict a spike in an organisation’s energy usage and advise them in advance so they can take action to reduce or defer consumption. Real-time data feeds the results back to customers via the app - they can immediately see the results of their actions or inaction and understand the cost implications.
With more connected things than people in the world now and the number still growing exponentially, IoT and big data will undoubtedly lead to far more automation in the way energy is consumed and managed behind the meter.
As more businesses install their own infrastructure behind the meter, whether it’s solar, embedded generation or other new technology, this will create even more meaningful data sets that can be incorporated into modelling. New types of sensorequipped devices will provide more granular data, with the potential to drive more accurate outcomes for businesses with very little human interaction.
The two-way connectivity that these devices will enable will change the way organisations view and manage their operations in the future. For example, machines may run when prices are favourable, and demand is low, or when businesses are generating their own energy to reduce consumption from the grid. This is a clear example of automation driving energy optimisation in business.
Data is continually and rapidly transforming the future of energy management. The opportunity for Australian business is to harness its power to create a sustainable, competitive advantage.
By Ivor Frischknecht, Chief Executive Officer, Australian Renewable Energy Agency.
In the decades to come, it is increasingly clear that much of the future will be ‘behind the meter’. Or to be more precise, the future is going to be distributed.
Even the phrase ‘behind the meter’ is antiquated, as it draws a line between the customers and the rest of the energy system. It frames the whole electricity system from the perspective of the traditional industry players — the retailers and the networks — instead of from the customer’s point of view.
What’s behind the meter all depends after all on which side of the meter you are standing on and which way you’re facing. From the Australian household’s point of view, the whole electricity system is ‘behind the meter’ – not the other way around.
If millions of Australian households and businesses continue to invest in their own solar and battery storage systems, this vast array of decentralised consumer energy assets could create enormous headaches for the electricity market, its operator, regulator, retailers and networks. It also creates opportunities.
In the last decade, Australians have embraced rooftop solar so enthusiastically we are now the biggest rooftop solar adopters per capita in the world. Ten years ago, there were just 14,000 rooftop solar units across Australia.
Today, nearly 1.8 million Australian households now have solar panels on their rooftops, accounting to 6.4GW of generation capacity.
And that is only increasing. Rooftop solar installations hit a new monthly record in the March quarter just passed with 127MW installed, up 56 per cent from the same time last year. Rooftop solar installations are running at an annualised rate of more than 1300MW. An estimated 1GW of rooftop solar was installed across Australia last year alone. For the first time, rooftop solar throughout Australia generated over 1000GWh in December last year.
The uptake of rooftop solar PV among commercial and industrial customers is also increasing apace with businesses outstripping residential customers.
In the next two decades, AEMO has forecast that rooftop solar will grow by at least 10,000MW, which equates to a fifth of all of Australia’s existing generating capacity.
By 2040, according to some current forecasts, 25 to 40 per cent of Australia’s generation will be coming from solar PV on the rooftops of households and businesses. To put that in perspective, at present, rooftop solar generation accounts for just three per cent of our generation.
While grid-scale generation will always be needed, this increase in solar PV and other distributed energy resources (DER) represents a huge disruption to the National Electricity Market, and a huge challenge for the electricity system to grapple with.
On the other hand, it also represents a huge, untapped
opportunity to make these DER work for the system, rather than against it.
For example, it leads to a situation where demand for electricity — which was once highest in the afternoon — becomes very peaky, where demand is very low during the day while the sun is shining and suddenly demand spikes once the sun goes down as all of the rooftop solar is no longer available.
Thanks to compulsory registration schemes, we can track where rooftop solar is installed but we don’t have visibility on how much electricity they are generating. Rooftop solar cannot currently be monitored or coordinated. We can’t optimise their output the way we can with grid-scale assets.
Home batteries present an even greater challenge. With home batteries, we don’t even know where they are in the system or how many of them there are, let alone what they are doing and we can’t control them externally.
In the coming decade, the cost of residential batteries is expected to plummet. If forecasts are accurate, the global cost curve of batteries will continue to fall as their size and capacity increases – much like computers have become smaller, faster, smarter and less expensive.
If residential batteries become cheaper and more efficient, we can expect a large number of Australian households to adopt them – particularly those that already have solar on their roofs. Last year alone, the number of Australian households installing home batteries more than doubled, from 1566 in 2016 to 3763 in 2017. And this is just the beginning.
Apart from storage, there are other technological innovations that are coming that will change the way we use electricity in our homes and businesses. More Australians will be driving electric vehicles that they charge in their homes. The Internet of Things will allow appliances to be automatically optimised for energy efficiency, and smart thermostats and smart pool systems will become the norm.
In a future where millions of Australian households have solar PV on their rooftops, home battery systems and smart appliances all capable of working together, these assets will not only change the way we use electricity but will also necessitate that we change the way we think about the system.
If we don’t enable these assets to be monitored and optimised, it creates the potential for a future Australian electricity system with limited visibility, lots of instability and the need for lots of new network infrastructure to balance this. This would in turn lead to even higher network costs than Australians are already paying for.
While those lucky enough to afford their own rooftop solar and
storage would experience cheaper energy costs and would be largely self-sufficient in the grid, this could be at the expense of others who cannot afford their own solar and storage who would bear the cost of network upgrades built into their power prices. All of this can be avoided however.
There needs to be a massive enablement of rooftop solar, batteries and controllable loads so they deliver benefits back to the system as a whole, with participation on a voluntary opt-in basis. This will include ways to sensibly manage demand, including incentivising the use of demand side resources as happens in other countries from Texas to Taiwan.
If consumer energy assets can be orchestrated and optimised so as to work harmoniously, distributed energy resources could save consumers money on their power bills, reduce the need for network infrastructure, help deliver grid stability services and inject dispatchable power back to the grid when and where it is needed.
To deliver this, there are certainly technical challenges to overcome. However, this shift to distributed energy also creates commercial issues and regulatory challenges.
We need incentives for people to allow access to their solar and battery storage devices and appliances. We need commercial and business to benefit from integrating into the system. We need new business models to drive this innovation so it is seamless and automated. We need new market rules to allow these unregulated assets to be valued as part of the energy mix.
Retailers could become the future orchestrators of consumer energy, but at the moment their existing business model is to sell electricity to customers.
Networks also have an important role to play, but existing networks make money through regulated returns from expenditure on grid infrastructure.
In the US, cable companies are becoming new consumer energy enablers. In Australia, it is conceivable that this “energy enabling” might be done by telecommunications companies, or it could be a service offered by tech giants like Google, Amazon and Apple who are moving into home automation technologies.
Already, ARENA is supporting a wide range of studies and pilot projects that look at how to optimise consumer energy.
In South Australia, AGL is already rolling out their virtual power plant project involving 1000 AGL customers in Adelaide, by aggregating 1000 batteries in 1000 households and businesses.
Earlier this year, Simply Energy announced a $23 million project in Adelaide, with $6 million in ARENA grant funding to create a virtual power plant consisting of 1200 households totalling 6MW of capacity, and a further 2MW of demand response from commercial businesses.
This will involve installing subsidised Tesla Powerwall 2 batteries in households with existing rooftop solar, which will then be coordinated and aggregated. This virtual power plant will also involve the ARENA-funded Greensync’s deX platform and the South Australian Power Network.
In Victoria, ARENA is also supporting a feasibility study into a “virtual microgrid” for the Latrobe Valley. US-based energy startup LO3 created and manages the Brooklyn Microgrid, and would look to create a local energy marketplace of 200 dairy farms, 100 households and 20 other commercial and industrial businesses in Gippsland.
This “virtual microgrid” would see these customers install solar and storage, and would allow them to buy and sell their renewable energy locally using blockchain-based peer-to-peer energy trading platform Exergy.
Last summer, ARENA and AEMO also kicked off a three-year trial of demand response. This trial is funding 10 pilot projects to deliver 200MW of demand response emergency reserves across three states in NSW, Victoria and South Australia.
Most of these pilot projects are trialling paying energy consumers — both commercial and industrial customers and residential customers — to be on standby to conserve energy during extreme peak demand events, such as a summer heatwave. All participation in these schemes is voluntary and all businesses and residential consumers benefit from their involvement.
Beyond this trial, ARENA has also funded a Sydney boutique energy retailer Pooled Energy to trial smart pool system technology in 5000 swimming pools across NSW, which uses cloud-based software and sensor-based control systems to optimise backyard swimming pools so they can be turned into controllable loads.
In March, ARENA announced a $12.5 million DER funding initiative. Under this initiative, ARENA has called for pilot projects to look at improving network hosting capacity and for studies to look at improving orchestration and integration of high levels of consumer energy.
It is too early to say which of these new business models or new technologies might ultimately be the best way to enable and integrate distributed energy, but one thing is certain; we cannot afford to ignore the customer side of the equation.
In a future where the customer side of the system has a huge role to play in delivering supply and managing demand, our current industry-centric view of the system has to change.
Instead, we need to think about the energy system holistically – and that includes finding ways for customer’s household solar, batteries and appliances to be utilised for the benefit of the system as a whole.
SBetween 2005 and 2015 the value of the electricity grid – the poles, wires and substations that transport electricity from generators into our homes and businesses — increased by $40 billion in real terms. This 70 per cent increase was a major reason electricity bill increased so much over the same period. But while the value of the grid ballooned, our use of the grid grew only modestly. So why all this extra spending on infrastructure? This is the question that the latest Grattan Institute report, Down to the wire, tries to answer.
pending on network infrastructure is important. When consumers start using more electricity during peak periods – as has happened with the widespread adoption of air conditioning – the existing networks need to expand. When new houses and suburbs are built – as is happening as Australia’s population booms –new infrastructure is needed to connect these households to the grid. And as infrastructure ages, it needs to be replaced.
But our report found, even after taking these factors into account, that network businesses spend up to $20 billion more on infrastructure than was needed. And most of this excess spending occurred in just two states: up to an extra $11 billion in New South Wales and up to $7 billion in Queensland.
There are a number of reasons.
First, expected increases in peak demand never materialised. Everyone
thought electricity demand would continue to grow in line with economic growth. But in 2009, electricity demand began to fall and then flatline.
Second, network businesses that are owned by state governments can have different incentives than a privately-owned business. Publicly-owned businesses may prioritise local procurement over cheaper foreign options. They may, under pressure from their political masters, give priority to making the system even more reliable, rather than seeking to provide electricity at the lowest cost.
That’s what happened in NSW and Queensland. In the middle of the 2000s, the governments of those two states imposed strict reliability standards on their network businesses. They did so in response to some high-profile blackouts and safety concerns, which had attracted a lot of media attention.
As a result, network businesses had to build a lot more stuff to strengthen their networks. Eventually, some of the reliability standards were either removed or eased. But not before the damage was done.
The network businesses had already spent up big – and consumers in NSW and Queensland were left with the bill. Consumers in NSW, in particular, have paid an awful lot of money for a quite-limited improvement in reliability.
Of course, politicians want to take action when blackouts occur, as we have seen recently in South Australia. No one wants to be left holding the baby when the lights go out. But immunity from reliability problems doesn’t come for free.
Grattan’s Down to the wire report shows a common link between the businesses that overspent; they were all publicly owned. This fact does not ‘prove’ that private is better than public; there are a range of factors that together resulted in network businesses overspending. Nonetheless, the evidence suggests privatisation of the electricity businesses in Victoria and South Australia has benefitted consumers in those states.
The businesses in Victoria and South Australia have spent less, maintained decent reliability and kept network costs down, compared to the publicly-owned businesses to their north. That’s why our report recommends the privatisation of remaining publicly-owned network assets.
But even if the businesses are privatised – and this seems unlikely – there is still the issue of what should be done about that $20 billion of unnecessary spending.
The excess investment has made grid-based electricity more expensive than it should be. That will drive more consumers to get off the grid and on to solar power and other off-grid alternatives. And that in turn will mean those consumers who remain wholly reliant on the grid will need to pay still more for their grid-based service.
Only by making sure that the price of grid-based electricity reflects its true value can policymakers ensure efficient investment decisions are made and equitable outcomes achieved.
To this end, we proposed that, where government still owns the network business, they should write-down the value
of their assets in line with the overspend. This would not create sovereign risk: as owners, the government can do pretty much what they want to their businesses without creating sovereign risk for privatelyowned businesses.
Nor would it require changing the regulatory framework, which could impact on other network businesses in the National Electricity Market.
electricity consumers a rebate
In the case of the recently privatised, or partly-privatised, NSW businesses, the state government doesn’t have such luxury. Changing the value of a privately-owned business creates all sorts of sovereign risk.
So instead, we recommend that the NSW Government pays all electricity consumers a rebate commensurate with the savings consumers would receive had a write-down of the assets occurred. In both cases – for the publicly-owned and privately-owned network businesses – consumers would get a reduction in their bills.
The problem of networks ‘gold-plating’ is not new. But it’s time to draw a line under the problem. Either governments act,
or they choose to accept that the excess costs are locked in for consumers.
As for the electricity grid itself, it faces greater challenges.
The grid is likely to remain vital to our future electricity needs. But the way it is used is changing, and how the grid will look in future is a big unknown. Electricity generation is becoming more distributed, more individuals are using the grid to both buy and sell electricity, and some are fleeing the grid altogether.
Working out how we build the right electricity infrastructure in the right places will be vital if we are to avoid a repeat of the massive overspending of 2005 to 2015.
IPS-SYSTEMS™ is a fully integrated and comprehensive Enterprise Asset Management (EAM), Asset Performance Management (APM), Network Model Management and Mobile Solution, specialised for the global electricity industry, with large and ever expanding technical libraries of assets, technical data and analytics.
With big data and the IoT transforming the way asset information is managed in the digital age, more and more organisations are looking at implementing advanced EAM software to ensure assets operate more efficiently and with minimal disruption.
By setting up a dedicated EAM platform, utilities can monitor and analyse the real-time condition of their assets, offering more informed decision-making and opportunities for preventative maintenance, and asset life extension. With concerns about aging assets and the cost of replacement, utilities are seeking maximum cost efficiency and return on their assets.
IPS-ENERGY’s Asset Performance capability is world-leading, with highly advanced software and analytics to accurately assess asset health and predict asset lives, undertake what-if analysis, and capex and opex optimisatio n.
Highly-intelligent asset, configuration management for protective relays and IEDs (a must-have for high level of power system security, reliability and flexibility), is just one of our key differentiators.
Another one is our CIM XML, Topology and Network Model Manager functionality, which provides you with one centralised set of validated system network model data, for multiple users to implement in:
» Network planning
» Network analyses
» Asset management and more.
Our new state-of-the-art Mobile Solution (IPS-MobApp), has both online and offline capability, and leading-edge dynamically-changing work tasks and action lists, based on field data collection and instant asset analytics, providing superior predictive maintenance capability, as well as voice recognition, machine learning asset nameplate and condition photo recognition and analysis.
According to Gartner, the world’s leading IT research and advisory company, utilities looking for a product tailored to an engineering focus on physical characteristics should consider IPS-SYSTEMS in their shortlist.
IPS-ENERGY Australia Pacific is the Australian branch of IPS-Company Group, a global organisation headquartered in Munich, Germany, that specialises in EAM and APM for electrical power utilities.
If you would like to have more information or see a demonstration of IPS-SYSTEMS™ software and analytics and IPS-MobApp solution, please contact us at any time as per details below and/or come to see us at Booth No. 27 at Energy Networks 2018
For more information and product specifications, visit www.ips-energy.com, call +61 3 9042 8081 or email info.au@ips-energy.com
The dragonfly is a creature of intrigue, its appearance and behaviour fascinating to many cultures and civilisations. Universally, the dragonfly symbolises power and poise through its ability to move in all six directions at amazing speeds with graceful agility. The name dragonfly has its source in the myth that dragonflies were once dragons, thus the genus name ‘odonata’ meaning ‘tooth’. The espionage group ‘Dragonfly’, infamous for its attacks on energy security systems, has resurged to take some vicious bites.
Late last year, Symantec reported that Dragonfly, suspected to have its roots in Russia, was targeting Europe and North America’s energy sectors in a new wave of cyberattacks. The group, in operation since at least 2011, re-emerged as “Dragonfly 2.0”.
Issues relating to cyber security are generally considered by the public to be a financial services and privacy concern: credit card fraud, identity theft etc. What many people never think about is an attack in the energy space. A compromised grid could bring a city (or country) to its knees if essential infrastructure and services are cut such as water, electricity, gas supplies, hospitals, transport.
Recent global events have forced the doomsday scenario to the fore with politicians and sector leaders speaking publicly with unprecedented candour and immediacy.
Putin’s recent warning to Great Britain was stark; there are incumbent “consequences” to be suffered for the Syrian airstrikes. In response, Britain’s Foreign Secretary, Boris Johnson, raised the alarm, saying an imminent cyber backlash could see Britain’s vital services affected.
“You have to take every possible precaution, and when you look at what Russia has done, not just in this country…
attacks on critical national infrastructure –of course we have to be very, very cautious indeed.”
Mr Johnson warned that cyberattacks undermine “civilised values”, fearing that hackers could force electricity blackouts and cripple the grid. A few weeks prior, an industry taskforce was announced to draw up a strategy to restore the grid in the event of a nationwide power failure triggered by a cyberattack.
Ciaran Martin, Director of the National Cyber Security Centre (NCSC), the public face of UK spy agency Government Communications Headquarters (GCHQ), confirmed that Moscow’s attempts at hacking into the UK’s energy network over the last year was part of a larger effort seeking to undermine the international system’s critical infrastructure, suggesting it is a matter of when, rather than if.
Jeremy Fleming, GCHQ’s Director, launched a blistering attack on the Kremlin, simultaneously warning that the online threat from Moscow was ill addressed at peril.
“The Russian Government widely uses its cyber capabilities. They’re not playing to the same rules, they’re blurring the boundaries between criminal and state activity.
“To stay ahead, to match the pace of technological change, we are investing in deploying our own cyber toolkit. It’s one
that combines offensive and defensive cyber capabilities, to make the UK harder to attack, better organised to respond when we are, and able to push back if we must.
“We may look to deny service, disrupt a specific online activity, deter an individual or a group or perhaps destroy equipment and networks.”
The threat posed by Dragonfly isn’t just a threat for European countries; the United States has been on cyber threat alert for some time, particularly since the allegations of Russian interference in the 2016 Presidential election.
In the energy sector, the North American Electric Reliability Corporation (NERC) set up the Electricity Information Sharing and Analysis Center (E-ISAC) in 1999. Originally focused on physical security, in recent years E-ISAC has greatly broadened its remit to provide unique insights, leadership and collaboration, particularly on high impact low frequency (HILF) events.
An ongoing challenge is the unknown nature of what each attack may involve; a coordinated attack could be a combination of physical and cyber threats, and this underlines the need for a collaborative, cross agency approach. E-ISAC has undertaken four biennial GridEx grid security exercises.
GridEx is an unclassified public/ private exercise designed to simulate a coordinated cyber/physical attack with operational impacts on electric and other critical infrastructures across North America and beyond, in order to bolster preparedness, resilience and reliability.
Cyberattacks in our space have been foreseen. A 2015 survey of 625 IT executives in the US, UK, France and Germany found that 48 per cent thought a cyberattack on critical infrastructure, including energy infrastructure, by the year 2018 resulting in loss of life, was likely.
Our new Minister for Law Enforcement and Cyber Security, Angus Taylor, warned that in our efforts to thwart the Dragonfly, businesses, agencies and departments mustn’t entrench silos even further, but should collaborate and share.
"The key in cyber, like most areas, is speed and that means you've got to share information in a collaborative way.”
At March’s Senate committee examining the digital delivery of government services, Australian Signals Directorate (ASD) Director-General, Mike Burgess, berated department heads for being secretive when it comes to cyber security.
"There is a possibility that those who aren't taking this seriously don't ask for our help. That would be a risky strategy for any chief executive.”
Last year, Australia launched a national $230 million cyber security strategy, led
by attorney general George Brandis, with particular attention on the energy sector. Securing critical infrastructure assets in partnership with industry was a key focus.
"With increased foreign involvement, through ownership, offshoring, outsourcing and supply chain arrangements, Australia's national critical infrastructure is more exposed than ever to sabotage, espionage and coercion," Mr Brandis said.
While legislative steps have been put in place to protect critical infrastructure, what is industry doing to protect its assets?
The Finkel Review’s examination of the future of Australia’s National Electricity Market (NEM) recommended a heightened emphasis on cyber security, with an annual report considering the NEM’s cyber security preparedness.
The review also recommended an Energy Security Board (ESB) that would coordinate whole-of-system monitoring of security, reliability and planning. The ESB was established in late 2017 and espousing collaboration, works with key agencies including the Australian Cyber Security Centre, the Critical Infrastructure Centre, the Department of Defence, ASD, ASIO, and Prime Minister and Cabinet.
The Federal Government and AEMO have ultimate responsibility for the sector’s response to cyber threats, however, Energy Networks Australia has designed programs to complement and add value to those work streams.
Energy Networks Australia’s cybersecurity program is, together with our members, reviewing networks’ resilience and capacity, with a final report expected in June 2018. Litmus, the independent consultant leading the study is utilising the internationally recognised US Department of Energy’s Cyber Security Capability Maturity Model (C2M2) assessment tool.
Networks are collaborating with AEMO (which has ultimate responsibility for our nation’s grid security) to ensure the findings of our program can be used to inform the Cyber Security Industry Working Group (CSIWG) and mitigate threats.
Networks are also working with Standards Australia to undertake a review of technical standards and international protocols. A future roadmap will consider the most appropriate technical cyber standards for Australia.
Examining how our nation’s information and technology planning matches up with international standards will complement the Cyber Security Industry Working Group task to develop a holistic cyber security framework for Australia.
Energy Networks 2018’s June conference will take a deep dive into cyber security and leaders in our sector will share how we can best protect our assets.
The adage about an ounce of prevention being worth of a pound of cure is apt in relation to cyber security; the strongest insect repellent we have to stymie the Dragonfly is continued information sharing, timely communication, cross agency working and agile, expedient solutions.
by Louis Brailsford, Energy Advisor, The Climate Council
Australia is currently enjoying an energy storage boom. In 2017, Australians installed more energy storage (batteries, solar thermal and pumped hydro) than any other country in the world, with 246MW of power capacity added to the grid, according to a GTM Research report released recently.
Australia was also second in the world for energy capacity (MWh) added, just behind the United States. To cap it all off, Australia was number one globally for household storage installations. Australia’s love affair with the technology is growing in leaps and bounds, with no signs of slowing down.
The combination of high electricity prices, the falling costs of renewable energy and batteries, and supportive state government policies have turned Australia into a world leader on energy storage in the space of just a few years.
Australia has very high electricity prices. Between 2007/8 and 2015/16, Australia’s electricity prices were driven up by over investment in the poles and wires of the electricity network. High gas prices, lack of competition and policy uncertainty have also played a role in Australia’s high electricity prices.
The high cost of electricity has meant that new technologies, particularly batteries, are becoming competitive with established technologies more quickly than they otherwise would. Grid-scale batteries are already competitive
with peaking gas power stations, as has been recently demonstrated in California, where solar and batteries are beating out gas to provide electricity during peak periods at the lowest cost.
The high cost of electricity has been one of the main drivers behind the rapid uptake of household solar. Household solar in Australia has reached over 6,000MW – over twice the size of Australia’s largest coal-fired power station.
With many Australian homes now generating some of their own electricity, many households are
considering installing batteries as well. In 2017, over 20,000 households installed batteries – three times the total for 2016.
Batteries enable households to store electricity during the middle of the day – when solar panels are producing the most electricity – and discharge it in the evenings, when more power is needed.
While household energy storage is not yet an affordable option for all households, it is not far away. Battery costs have already fallen by around 80 per cent since 2010 and may halve again by 2025.
Of course, large-scale energy storage can also bring many benefits to the grid, particularly when it is installed at the site of generation or at weak points along the network. Numerous large-scale energy storage projects – batteries, pumped hydro and solar thermal – are underway across Australia, with many more projects in the planning stage.
Australia’s National Electricity Market is one of the longest electricity grids in the world, extending from regional Queensland, down to Tasmania and South Australia, with states and territories connected by a small number of high voltage transmission lines called interconnectors.
With such a long skinny grid and large distances between the sources of generation and consumption, energy storage – particularly batteries –can play an important role in securing electricity supply.
Power grids must operate within specific technical requirements (such as frequency and voltage) to maintain a reliable and secure supply of electricity, avoiding blackouts. Batteries can respond far more quickly to fluctuations in electrical frequency and voltage than other generators.
For example, batteries can respond almost instantly to changes in frequency when large coal and gas power stations experience unexpected breakdowns, ensuring electricity supply can still be delivered safely.
Batteries can also help reduce electricity prices across the board by eliminating price spikes that occur in the frequency control and ancillary services markets (FCAS).
In South Australia – before the TeslaNeoen battery started operating in December – FCAS services were provided by just four gas power stations, all owned by major electricity companies: Origin Energy, AGL and Engie.
When the Heywood interconnector that connects South Australia’s electricity supply with Victoria is not operating, the Australian Energy Market Operator (AEMO) needs
35MW of capacity from these large power stations to provide these essential FCAS grid services. On numerous occasions, these generators have restricted FCAS supply, driving up the cost of these services by millions of dollars.
Today, South Australia’s “big battery” can also provide FCAS services. The increased competition is already reducing prices. The cost of one type of FCAS (called raise and lower regulation) is estimated to have fallen to just $39,661 in December 2017, compared to $502,320 one year earlier.
Australia’s embrace of energy storage can also assist the transition to a 100 per cent renewable energy powered grid, playing a crucial role in cutting the nation’s greenhouse gas pollution levels that have been increasing every quarter since March 2015.
In order to avoid the effects of intensifying climate change, such as extreme weather events, Australia must rapidly transition to a clean economy and a key part of this transition involves moving away from fossil fuels towards renewable energy sources, like wind and solar.
Energy storage technologies can store electricity from wind and solar farms during periods of low demand. They can then supply electricity into the grid when demand is higher but wind and solar generation is lower, ensuring a continuous and reliable supply of electricity. As noted above, energy storage can also deliver other important services to ensure the security of the electricity grid.
Pumped hydro in particular has a key role to play in the transition from fossil fuels to renewable energy. Pumped hydro can store large amounts of electricity which can then affordably supply the grid for several
hours. 22,000 potential pumped hydro sites have been identified around Australia, including abandoned mine sites, and it is estimated only 0.1 per cent of these sites would need to be developed to support a 100 per cent renewable electricity grid.
In Queensland, the abandoned Kidston Gold Mine is being converted into a pumped hydro power station that may be able to provide 2,000MWh of energy storage.
Australia has become a global leader in energy storage. This places Australia in a unique position to speed up our transition to a renewable electricity grid. An energy system powered by renewable energy and storage can deliver power 24/7, help reduce electricity prices by increasing competition, improving the flexibility and security of the electricity system, and reducing Australia’s reliance on expensive gas – all the while reducing pollution and tackling climate change.
The Hornsdale Power Reserve Battery Energy Storage System (HPR) – the world’s largest lithium-ion battery – underwent its first charges and discharges into the grid at the end of November 2017. The Australian Energy Market Operator’s (AEMO) recent paper, Initial Operation of the Hornsdale Power Reserve Battery Energy Storage System, highlights the results from this initial period of operation and outlines what future large-scale batteries can learn from this system.
The battery covers approximately one hectare of land, located at the Hornsdale Wind Farm 15km north of Jamestown, near Adelaide in South Australia. The HPR is connected adjacent to the 300MW Hornsdale Wind Farm.
The HPR provides a range of services under commercial agreements between the South Australian Government, Tesla (the battery technology provider), and NEOEN (the operator of the Hornsdale Wind Farm and the battery system).
Operation of the HPR to date suggests that it can provide a range of valuable power system services, including rapid, accurate frequency response and control.
Rated at 100MW discharge and 80MW charge, the HPR battery has an energy storage capacity of 129MWh. This means the HPR battery is able to provide 100MW of services into the National Electricity Market (NEM), for a duration of 1.29 hours.
Under normal conditions, 30MW of the battery’s discharge capacity is made available to NEOEN for commercial operation in the NEM. Of the battery’s total 129MWh energy storage capacity, 119MWh may be used for this mode of operation.
The remaining 70MW of battery discharge capacity is reserved for power system reliability purposes. This 70MW reserve capacity has not been dispatched to date.
Under arrangements with the South Australian Government, this capacity is
offered into the NEM at the Market Price Cap, ensuring this component of the HPR will not be dispatched ahead of other generation in South Australia.
The HPR is registered to provide all eight Frequency Control Ancillary Services (FCAS) markets, and this is the first time regulation FCAS has been provided in the NEM by any technology other than conventional synchronous generation.
AEMO’s central Automatic Generation Control (AGC) system can be used to control the HPR, and this is the normal control arrangement most of the time. AGC control allows AEMO to send a new MW setpoint to the battery at a rate of up to once every four seconds.
This enables the HPR to provide regulation FCAS in South Australia. This market has seen high prices for this service for the two years prior to the battery becoming operational.
Regulation FCAS incrementally adjusts the output of the battery up or down, away from an underlying energy dispatch target, to correct slow moving frequency changes across the NEM. Up to 30MW of the battery’s output capacity is available for provision of regulation FCAS.
Data available to AEMO demonstrates that the regulation FCAS provided by the HPR is both rapid and precise, compared to the service typically provided by a conventional synchronous generation unit.
While experience shows that the HPR is capable of providing very high quality regulation FCAS, regulation FCAS arrangements in the NEM do not currently recognise differences in the “quality” of service delivery.
The Market Ancillary Services Specification (MASS), which specifies each market ancillary service and how it is to be quantified, does not address performance requirements for regulation FCAS. All regulation FCAS is essentially considered to be equal and interchangeable, and providers are paid the same price per MW of enabled service, regardless of performance.
This method of assessing and commodifying frequency response involves performance assessment against a slow moving change in frequency, and therefore does not recognise, or reward, the more rapid response capabilities of batteries, and some other inverter-based technologies.
Changes in how frequency response is assessed and paid for may be required in order to acknowledge the high performance and quality of regulation response available from batteries.
In some overseas markets, new frequency control services with very short delivery time requirements have been established, which are typically only fulfilled by batteries.
Care would be required in establishing new markets, or modifying the assessment of frequency response capabilities in the NEM, to consider the current complex
interactions between the dispatch of FCAS and energy in the NEM, the potential need to maintain technology neutrality, and the potential for limited competition in the delivery of any newly defined services.
AEMO will work with industry to undertake formal consultation on the necessary modifications to the MASS.
The funding arrangements for the HPR meant there was a focus on ensuring all its capabilities were fully utilised to maximise power system security for South Australia.
This included engagement with AEMO when control settings and operating arrangements were determined, in a way that would not typically occur for other generation development (where the project developer is responding to existing market signals and arrangements).
Future development of batteries outside of South Australia might not result in the provision of similar services, due to the way FCAS are currently quantified and rewarded, as well as the voluntary nature of participation in the FCAS market, and
in frequency control arrangements more broadly.
Where other large batteries are established under government incentive schemes, there could be a role for a more prescriptive provision of system security services, to maximise the benefits to the power system that such devices can provide.
Current FCAS market arrangements could also be modified to specifically recognise the rapid and accurate response capabilities of batteries, and therefore enhance their ability to earn income from providing them.
The HPR has been configured to provide a contingency FCAS response at all times, irrespective of FCAS market outcomes, using the full technical operating range of the battery.
Because major frequency deviations in the NEM are (fortunately) rare, actual full delivery of this service has not yet been demonstrated.
The HPR is also included in a new control scheme intended to prevent the
likelihood of the South Australian power system separating from the rest of the NEM as a result of a sudden increase in flow on the Heywood Interconnector.
The System Integrity Protection Scheme (SIPS) was developed by ElectraNet and reviewed by AEMO, and it is being implemented by ElectraNet under the Network Loading Control Ancillary Services (NLCAS) framework.
The SIPS control scheme is intended to detect high flows on the Heywood Interconnector and trigger the HPR to start discharging at 100MW as quickly as possible.
Future batteries installed in South Australia may also be included in this control scheme. A key feature of this control scheme is the very rapid response that can be achieved using battery systems.
The South Australian NLCAS requires 10MWh of the HPR’s total energy storage capacity to be reserved for the control scheme. It is expected to be fully commissioned in the second quarter of 2018.
To watch a video of the Australian Energy Market Operator’s visit to the Hornsdale Power Reserve battery, please go to www.youtube.com/watch?v=AOXdWeBS_tI.
As international efforts ramp up to meet commitments of the Paris Accord, Australia is driving towards a low emissions future that delivers reliable, environmentally responsible, affordable energy.
But there’s a challenging road ahead which will require long-term commitment and investment in technologies that can deliver reliable, affordable, low carbon electricity as we shift from a grid that is based around centralised baseload and peaking generation to a smart grid with increased supplies of renewable energy and distributed energy resources.
The Clean Energy Finance Corporation (CEFC), which was established by the Australian Government in late 2012, has made cumulative investment commitments of more than AU$5.8 billion to projects with a total value of more than AU$16 billion.
These investments make us Australia’s largest debt financier for grid-scale solar PV, and the largest single investor in Australia’s clean energy venture capital market through our Clean Energy Innovation Fund.
Through our investments, we have built a substantial, diverse portfolio of renewable, low emissions and energy efficient technologies that are supporting decarbonisation pathways across the breadth of the Australian economy.
Our investments to date are estimated to help achieve emissions reduction of more than 180 million tonnes of CO₂e over the life of their associated projects.
At the CEFC, we have made a conscious effort to invest in the application of technologies that have yet to reach their full potential in Australia. As providers of both debt and equity, we’ve also used innovative financing models and have been prepared to take a view on merchant power prices in financing a renewables market often short of offtake contracting.
At the same time, we’ve looked to encourage third party financiers to invest alongside the CEFC in our transactions. Leveraging our own capital builds confidence in the markets and facilitates increased flows of finance into the clean energy sector.
In the context of the decarbonisation challenge, the CEFC invests across all industry sectors of the Australian economy, focusing on decarbonisation pathways of low carbon electricity, ambitious energy efficiency, and electrification and fuel switching, as well as reducing non-energy emissions.
As we’ve already seen with the operation of the Tesla battery at Hornsdale Power Reserve in South Australia, large-scale battery storage has the potential to flex from charge to discharge in an instant, making it both a valuable tool to harness supply peaks produced through the variability of large-scale solar and wind generation, and a game changer for immediate responsiveness to peaks in energy demand and grid volatility.
There’s a growing case for cost competitiveness when battery storage is linked to large-scale renewable generators. Bloomberg New Energy Finance (BNEF) released data in late March 2018 that puts the average combined cost of onshore wind and solar PV plants paired with small batteries at between US$32 and US$110 per MWh.
This compares with a global figure for coal and combined-cycle gas (CCGT) plants providing fully dispatchable generation at US$40 to US$146 per MWh. BNEF says that while standalone batteries are competitive today for hitting narrow peaks, they are expected to be able to cover wider and wider peak periods as their costs decline.
But for now, rolling out lithium-ion battery storage at a much larger scale is still cost prohibitive. That’s where pumped hydro, with its long project life and large energy capacity, steps up.
Researchers at ANU have identified 22,000 sites around Australia suitable for pumped freshwater hydro energy storage and the Australian Renewable Energy Agency (ARENA) has been working on a number of feasibility studies for projects in Tasmania, South Australia’s Spencer Gulf and the expansion of the Snowy Hydro scheme in Snowy 2.0. Each site has storage potential ranging from one to 300 gigawatt hours.
As an accelerator of change, we’ve witnessed and supported the first significant shifts towards the increased inclusion of battery and storage technologies in both large and small-scale clean energy investment.
We’ve created new opportunities for grid-scale energy storage and investment in transmission that will be important for the reliability of our electricity system in the years ahead. Our own finance is working to further lower costs with our projects building experience across the construction and operation of large-scale clean energy generation and integrated storage solutions.
Our transactions demonstrating the benefits of batteries and storage include:
The CEFC has committed AU$94 million towards Windlab and Erus Energy’s Kennedy Energy Park which will be Australia’s first fully integrated wind, solar and
battery project. The natural benefits of the Kennedy Energy Park site in central north Queensland will deliver high levels of solar energy throughout the day and strong wind generation in the evenings, creating a reliable generation profile around the clock, while the addition of a 2MW battery will provide more predictable, reliable and low-cost electricity.
When operational, the Kennedy Energy Park will be capable of generating enough power for more than 30,000 average homes. The project will demonstrate the value of matching wind and solar generation to provide more predictable, reliable and low cost renewable energy. The addition of the battery component will provide even greater value to the grid.
Our AU$54 million investment with Genex Power assisted the development of Phase One of its Kidston Renewable Energy Hub, 270km north-west of Townsville — the construction of a 50MW solar farm, which is already generating energy and earning revenue from sales into the National Energy Market and through the sale of Large-scale Generation Certificates.
The solar farm is co-located with the proposed second phase of the project which will involve harnessing two large dams at the former Kidston Gold Mine site to develop a 250MW pumped hydro storage facility that will support around 1,500MWh of continuous power in a single six-hour generation cycle.
When built, this will be the first of its kind in Australia to co-locate a large-scale solar farm with a large-scale pumped hydro storage project, creating a combined generation and storage model for future projects.
The CEFC has also committed AU$150 million in debt finance to stage one of the Lincoln Gap Wind Farm in South Australia's Port Augusta region.
The project includes a 10MW battery energy storage system, capable of producing up to 10MWh of fast response storage capacity. It’s Australia’s first unsubsidised largescale grid connected battery alongside a greenfield wind development.
In the past year, the CEFC has witnessed a shift towards large-scale solar developers designing projects to incorporate technologies that will enhance their ability to supply energy seamlessly into the grid.
Sponsors are considering forecasting technologies and building projects that are “battery ready” so that storage can be easily added once the business case becomes suitably compelling.
The CEFC’s US$15 million (about AU$20 million) cornerstone investment in a bond is helping finance the development of Pilbara Minerals’ Pilgangoora lithium-tantalum project in Western Australia which will produce lithia raw materials that can be used to support a full range of lithium products for lithium-ion batteries and energy storage solutions.
The learnings gained through the development of these projects will provide support to the battery storage supply chain, build local construction expertise, help optimise revenue models and provide a strong knowledge foundation for future projects seeking storage technologies to overcome intermittency issues.
Harnessing flexible capacity and increased storage capacity will help us build a stronger, secure electricity supply at the same time as enabling the increase of penetration of renewable energy generation to help us reduce our electricity sector carbon emissions.
But large-scale projects are just part of the Australian battery storage story. Analysts are anticipating a shift towards increased levels of distributed energy resources (DER) over the coming decades, as customers embrace new technologies to take control of their energy costs and contribute to the decarbonisation challenge.
Research by the CSIRO and Energy Networks Australia to develop The Electricity Network Transformation Roadmap, predicts that by 2027 more than 40 per cent of electricity system customers will use on-site DER consisting of 29GW solar and 34GWh of batteries.
At the CEFC, we’re investing in projects that further prove up the effectiveness of distributed energy technologies to help reduce energy costs for both householders and business.
We’re working towards inspiring a “new normal” of new residential developments with built in batteries and solar, a greater adoption of innovative smart technologies that reduce grid energy consumption for businesses and an increased uptake of electric vehicles.
For example:
» GreenSync, a highly innovative clean technology company, is using smart software controls to produce a decentralised energy model that can integrate renewable energy supplies and battery storage systems into the grid and allows the grid to become a marketplace.
GreenSync's technologies allow large electricity consumers such as manufacturers, resorts and retail centres, to more closely monitor their electricity consumption and work with their suppliers to reduce their grid energy requirements.
An exciting new development is the deX, a decentralised energy exchange which enables energy users to capture the economic value of their demand side management activities. To support GreenSync scale up its operations, the CEFC invested AU$5 million through our Clean Energy Innovation Fund.
» Redback Technologies has developed a Smart Hybrid System that optimises solar generation, storage and management of energy for households and businesses. Redback's system uses machine learning to predict solar generation and customer usage. It then makes intelligent decisions to optimise energy usage, driving down energy costs for end users and reducing fossil fuel reliance.
Redback's software also enables systems to be aggregated to form a virtual power plant, to provide grid services and support increased integration of renewables into the grid. The CEFC has committed about AU$6.4 million through the Clean Energy Innovation Fund to support Redback’s business expansion.
» Mirvac masterplanned communities will incorporate solar and storage systems as part of the base build to offer around 300 state-of-the-art clean energy homes to first and new homebuyers. The rooftop and battery systems are expected to meet up to 90 per cent of a typical household’s energy consumption.
As a key part of the CEFC’s AU$90 million in finance towards the project, we will work with Mirvac to monitor energy use and track energy savings so we can share insights into the positive impacts of these technologies on day-to-day energy consumption.
» The CEFC is also working with Australia’s major banks and other financial institutions to support programs of finance to businesses looking to reduce their energy consumption through energy efficient, low emissions and renewable energy technologies.
Loans can be used for a range of initiatives including helping Australia move past the “early adopter” stage of electric vehicles by assisting businesses to upgrade their fleet vehicles.
The first steps towards a zero-carbon economy have already been taken, but we still have one of the most emissions-intensive electricity systems per capita among advanced economies.
While there is a long road ahead, we’re confident that with commitment, ambition and investment, the clean energy highway is one that will deliver Australia a secure, reliable and affordable energy system. Importantly it will also be one that is sustainable as we seek out an economy with net zero emissions in the second half of this century.
For more information, visit cefc.com.au
Standards Australia has several national committees developing Australian Standards, and also plays a key role in the development of international standards, for the energy and electrotechnology sector. This has meant there is a significant number of standards currently shaping the sector as a result of the work of Standards Australia.
The plan ahead for energy storage standards
Because energy storage remains a key issue for industry, government and the community, particularly given the trend towards renewable and efficient energies, Standards Australia has completed a report labelled, Roadmap for Energy Storage Standards
The report sets out the areas of priority for standards development to support the roll-out of energy storage systems in Australia.
The report has been flagged as addressing a priority for the Federal Government, following the comments of the Hon. Josh Frydenberg MP, Minister for the Environment and Energy, regarding standards being an important enabler for the effective roll-out of energy storage systems in Australia.
“The Energy Storage Standards Roadmap will support the COAG Energy Council’s commitment to ensuring regulatory frameworks facilitate the safe installation, connection, maintenance and operation of batteries.
This Roadmap is an important step forward in enabling the uptake of this emerging technology to support a transforming energy market,” Minister Frydenberg said.
Dr Bronwyn Evans, CEO of Standards Australia, explained how standards will support energy storage systems, both now and in the future.
“With rapid changes across all parts of the sector, it is important that we lay the right foundations and this includes having the right standards to assist innovation and support good infrastructure. It is imperative that technologies such as storage systems are safely, reliably and efficiently managed through a collaborative approach to standardisation,” Dr Evans said.
The report will serve as both a guide for standards development on energy storage and as a catalyst for international participation in standards development. Having been developed following two rounds of public consultation and an industry forum held in August 2016, this report has already brought together sections of the community, and collated views on what energy storage standards should look like in the future.
There is more work to be done in developing standards to support energy storage systems, but the report has outlined early foundations and the plan moving forward.
In 2017, the development of standards in the energy and electrical sector entered the battery storage space. This work was aided considerably by a three day meeting to progress critical work on the development of DR AS/NZS 5139, Electrical Installations – Safety of battery systems for use with power conversion equipment, hosted by Standards Australia.
One of the key outcomes of this meeting was to issue the standard for public comment for a second time. This was to allow additional consultation to ensure the Australian community was involved and supportive of this standard being
developed. Without community support, industry may have developed a standard falling well short of community expectations, leading to a whole range of possible issues in its implementation.
Given the breadth and depth of stakeholder consultation when developing standards, it can often be challenging to get a timely agreement from all parties. In the case of DR AS/NZS 5139, the adoption of AS IEC 62619:2017, Secondary cells and batteries containing alkaline and other non-acid electrolyte –Safety requirements for secondary lithium cells and batteries proved advantageous in speeding up the work.
The advantage of this particular international standard was in providing additional safety guidance around the installation of battery systems. This guidance was also coupled with an Industry Best Practice guide, facilitated by the Electrical Safety Office of the Queensland Government with a number of additional key industry members.
Not only is this standard helping steer Australia towards a more energy efficient future, but it also shows a strong commitment to improving safety for professionals and consumers engaging with these battery storage units.
Adopting a related international standard, and working hand in hand with an industry guide on best practice has contributed heavily to the early progress of DR AS/NZS 5139, and is symbolic of the steps which will be vital to its eventual success.
The standards development process utilised by Standards Australia relies on technical experts to develop the standard in its initial stages. From here, the standard falls to the hands of the public during the public comment phase. It is here that DR AS/NZS 5139 was identified as a standard of considerable public interest.
Of the large number of comments received on the draft, many were related to how systems should be installed in a residential context.
The large response to the draft is perhaps indicative of a number of factors regarding the standard. While some have argued it raises problems with the standard, there is an opposing view that the significant response has more to do with the large number of stakeholders with an interest in the standard with industry, consumers and government all having a role to play in getting the standard right to ensure it delivers on core safety objectives.
It is important to also note that Australian Standards are voluntary unless called up by governments, and are only published if consensus is reached between industry, government and community interests.
Following the three day meeting on DR AS/NZS 5139, CEO of Standards Australia, Dr Bronwyn Evans, said, “There was unanimous agreement in the room of the need to both encourage the uptake of new technology and manage community safety expectations. The clear path forward set today will see us working hard and working together to get the relevant standards in place as soon as we can.”
Standards Australia is committed to the work of developing standards that increase the safety of the Australian public, while simultaneously shepherding Australia towards a more energy efficient future.
The roll-out of standards in the energy storage space will continue in coming months. DR AS/NZS 5139 is progressing towards publication while key objectives of the report (Roadmap for Energy Storage Standards) will also be pursued for the sector. Keeping professionals and consumers safe when interacting with energy storage installations remains a key priority, and is a clear goal, in all of the Standards Australia projects in this field.
The ideal scenario for any energy user is to have a network that works without people having to think about it. With current supply and reliability issues, the industry is turning towards energy storage to increase reliability and support the uptake of renewable energy. In the lead-up to his presentation at the 2018 Australian Energy Storage Conference and Exhibition, we caught up with Dr Kevin Moriarty, Executive Chairman at 1414 Degrees, to discuss the current energy storage options in the market and why he believes silicon thermal energy storage is a game changer.
Dr Kevin Moriarty has had a lot of experience in Australia’s mining sector before he saw an opportunity to move into energy storage and now heads up 1414 Degrees who are supporting the uptake of silicon thermal energy storage.
Dr Moriarty said there is currently no implementation of silicon thermal energy storage in Australia yet, as it’s a new technology, but one he says is ‘groundbreaking’.
“There’s nothing quite like it in that it brings together a number of aspects of the common industrial applications, especially high temperature ones, and puts them together in a new way. So it’s using common things, but not in this combination.
“It’s not even in use anywhere, because it is literally groundbreaking,” Dr Moriarty said.
Silicon thermal energy storage systems store energy as latent heat in molten silicon. It delivers both heat and electric power and can be dispatched on demand. It’s this heat that Dr Moriarty said is more important than people realise.
“What we’ve been finding as we’ve gone into industry is that, on average, two-thirds of industries requirements are heat, one-third is power. But many industries...use 15 times the amount of heat than they use power.”
With the significant increase in the number of large-scale batteries and pumped hydro projects in Australia, and in particular, South Australia, it’s clear there is a need for energy storage to help increase the efficiency and reliability of the grid and reduce the risk of blackouts.
But why look to thermal energy storage when we already have other forms of storage that work?
“Well there’s a number of deficiencies to storage. Pumped hydro, which is very much in the news at the moment here in South Australia and Australia in general, in fact, is very useful for long-term storage, seasonal storage and so on, but you can’t put it anywhere, it’s got to be located somewhere where there’s mountains and plenty of water, and so on. So you’re quite limited in location. It’s also relatively expensive, and possibly environmentally challenging to set up,” Dr Moriarty said.
“Batteries don’t like being over-cycled. So the trouble with lithium batteries is they’re great for short-term fast-frequency response. The more you use them, the more they decline in capacity.
“What the thermal energy storage system does, is it can be located anywhere, it’s very compact, more compact in fact for energy storage than batteries [and] it has a very long life. In other words, the more you cycle it, preferably daily, the better it likes it. It’s a very robust new solution to energy storage.”
The rise of energy storage has come from the increase in renewable energy sources, which are inherently intermittent. While renewables have created forms of distributed generation, energy storage can help to reduce demand on networks and ensure that a backup supply is in place.
“With the rise of renewables we have distributed generation now, so you’re less dependent on any [one source], so that’s a positive. But on the other hand, if you can distribute storage through the grid as well, then you no longer have the exposure to any one big outage,” Dr Moriarty said.
Dr Moriarty said that while grid reliability is the goal, economics also play a big part.
“I don’t think multi-billion-dollar schemes are going to cut it, if their impact is felt in people’s taxes, or their electricity bills, or energy in general, in fact, because gas is very highly priced too. So when we looked at this, we realised that the silicon thermal energy storage system had the lowest levelised cost of storage of anything else out there. I’m talking pumped hydro, and batteries, flywheels, and so on.”
Dr Moriarty said silicon thermal energy storage will only get more compact over the next few years and become more common in the sector. When it comes down to it, he said that people just want their networks to not be an issue of debate, but rather one that isn’t given much thought.
“What you want is a grid, a network, electricity network, that works without people having to think about it, largely. Most of us want to turn on the lights, all of our machines at work, or know our refrigerators and freezers are going to stay on.
“So we need low cost, reliable things that operate in the background, and people don’t have to be thinking about them. We should hopefully get back to a grid that operates without a huge amount of fuss,” Dr Moriarty said.
Dr Kevin Moriarty will be discussing these issues, and more, in his presentation at the Australian Energy Storage Conference and Exhibition. This must-see industry event will run from 23–24 May at the Adelaide Convention Centre. To register for the conference or free exhibition, visit www.australianenergystorage.com.au/register.
by Paul Broad, CEO, Snowy Hydro
It’s hard to think of a time of greater upheaval in the way we produce electricity. For more than a decade, disagreement over climate and energy policies has stalled investment in new generation in Australia. Yet while the policy debate still rages, most companies in the energy market are operating under the assumption that, like it or not, we’re past the tipping point and are moving towards a low emissions future.
This is not to downplay the role that coal plays in the market. It is an important fuel source for electricity generation in Australia and will be for the foreseeable future. But as the country’s fleet of thermal power stations reach end of life, the market will make decisions about what will replace it.
Looking at the levelised cost of electricity (LCOE), which values the cost of energy generation across an asset’s lifetime, it is clear that in the energy market of the future the economics of coal-fired generation are no longer as attractive. The new entrant price for wind and solar, on an equivalent “firmed” basis, is now cheaper than new coal.
This trend is exacerbated as intermittency increases because it reduces the capacity factors of the coal plants. Capacity factor is a critical variable for the coal plants’ economics and the LCOE increases dramatically as capacity factor reduces.
Even with Australia’s vast, easy-to-extract reserves of thermal coal, the most modern, efficient coal-fired power plants cannot compete cost-effectively with utility-scale wind and solar. And given the LNG export boom and introduction of international net-back pricing, gas-fired generation is not a cost-effective solution for bulk energy either. Furthermore, the prohibition of onshore gas exploration is one of the factors that greatly increases the cost of gas-fired generation, whether it is used for mid-merit or peaking duties.
The changes currently being felt across the market are profound, and both generators and retailers are trying to adapt. Over the last decade, we have witnessed thousand of megawatts of thermal ‘base load’ generation capacity withdrawn from the market. This trend is only set to accelerate, with the progressive closure of Australia’s aging fleet of coal-fired power stations.
This lost capacity is, for the most part, being replaced by intermittent sources of generation, with large-scale wind and solar stepping into the void. Intermittency is one of the major contributors to system instability and price volatility in the National Energy Market (NEM), which can move very quickly from a market high of $14,200 to a negative price at -$1000.
The Snowy Scheme operated by Snowy Hydro currently provides large amounts of dispatchable generation to address intermittency of energy supply. At times of peak energy demand, the Snowy Scheme keeps the lights on and puts downward pressure on energy prices. The controllable dispatchability of hydro electricity is critical in meeting the demands of the current and future state of the NEM.
Snowy Hydro Limited, the largest hydro power generator in the NEM and a supplier of energy to more than one million customers through our retail brands Red Energy and Lumo, is about to embark on a major expansion of the Scheme through the Snowy 2.0 pumped hydro project.
Pumped hydro capitalises on price fluctuations and puts an effective cap on peak capacity prices. When demand is high, large-scale hydro can generate energy within minutes and when demand is low (or there is oversupply), Snowy Hydro can use the price differential to pump.
Snowy 2.0 is strategically located between the NEM’s two major load centres of Sydney and Melbourne and near the proposed renewable energy zones. Hydro generation is synchronous, producing inertia which helps stabilise the electrical network against oscillations associated with fluctuations in solar and wind output.
Snowy 2.0’s large-scale storage is best placed to provide firming to address the intermittency of renewable generation and therefore underpins its reliability and financeability.
Snowy Hydro expects to continue signing offtake agreements with incoming renewable generation. This not only gives Snowy Hydro increased capacity but it helps de-risk new projects by giving them a ‘floor price’ for off-peak generation. A recent example of this was the 20 year offtake agreement Snowy Hydro entered into with Equis’ 100MW solar plant being constructed in Tailem Bend, South Australia.
As a storage project, Snowy 2.0 is very cost effective and by far the cheapest form of storage on a megawatt hour basis. This ultimately means lower electricity bills for Australian consumers and businesses, in turn supporting the country’s international competitiveness.
The levelised cost of storage modelled in the Snowy 2.0 feasibility study was between $25–$35/MWh. Independent analysis has shown that if Snowy 2.0 is not built, the likely alternative is a combination of gas peaking plants and batteries at a cost of at least twice as much as our project.
The construction of the Snowy Mountains Scheme was one of the defining nation-building projects of the 20th century. It required long-term strategic thinking and vision – it wasn’t a quick fix.
The Snowy Scheme, consisting of nine power stations (including pumped storage at Tumut 3 Power Station and Jindabyne Pumping Station) and 16 major dams, collects, stores and releases water to users downstream and generates electricity on the way. It continues to be one of the most important sources of renewable energy in the NEM.
The Snowy Scheme acts like a giant battery that stores water (which is used to generate energy) and is always ready to smooth imbalances in supply and demand, and underpin the stability of the network.
Snowy 2.0 would massively expand the scheme, supercharging our existing capabilities by increasing output by 2,000MW and providing large-scale storage of up to 350,000MWh (which is equivalent to 175 hours of energy storage).
Snowy 2.0’s feasibility study, completed in December 2017, concluded that the project was both financially and technically feasible. Even with conservative parameters, Snowy 2.0 has a strong business case and an internal rate of return that exceeds eight per cent.
Independent energy market analysis conducted by Marsden Jacobs Associates confirmed that as intermittent generation increasingly enters the market, the demand for Snowy 2.0 (and the existing Scheme’s) energy market products will grow significantly. Snowy Hydro provides these products today and each presents a significant revenue opportunity:
» Capacity: The need to safeguard supply during periods of high energy demand has come into increasing focus. With the growth in peak demand, the supply/demand balance is more often under stress, particularly during summer. Snowy Hydro is already the leading supplier of energy price risk products in the NEM. These products (‘cap contracts’) insure retailers and customers against high price events, a regular feature of today’s energy market. Snowy 2.0 will create an additional 2,000MW of dispatchable supply, and so the number of cap contracts, and quite literally the generation capacity available to the market, will increase significantly.
» Storage: The basis of pumped storage is to pump water uphill during periods of low demand (low prices), and then use that water for electricity generation when the demand/ supply balance signals the profitable release of water. The sheer scale of the storage capability offered by Snowy 2.0 is unmatched. Other technologies will have a role in small-scale
energy storage, covering short intervals of time, but the NEM will need to adjust to cater for long periods of low generation. This includes wind "droughts" and cloudy periods which will result in below average generation for days, weeks or even months. Snowy 2.0 will maximise the value of renewable energy on a scale that alternative technologies cannot.
» Firming: With grid stability and energy reliability an increasingly urgent priority, Snowy Hydro will offer firming products which will provide an additional, complementary revenue stream. This is a hybrid of energy and capacity, and is most efficiently provided by large-scale hydro storage. Recognising the value of dispatchability and the need to firm-up the intermittency of variable renewable energy, the Energy Security Board recently recommended the creation of a reliability guarantee (as part of the broader National Energy Guarantee). Snowy 2.0 is ideally suited to provide this service.
» Ancillary services: The need for stabilising services, such as frequency and voltage control, will increase dramatically with the growth of intermittent generation. Known as ‘ancillary services’, these are critical to the reliability of electrical network. Snowy Hydro is already a major provider of these services and Snowy 2.0 will enhance that capability.
On the engineering front, the Snowy 2.0 project involves the construction of water supply tunnels from the existing Tantangara Reservoir (at an altitude of 1,230m), via an underground pump and storage cavern with outlet tunnels to the lower Talbingo Reservoir (at an altitude of 544m). The sheer size, scale of the project and the geology of the mountains presents a number of engineering challenges, however, we are confident we can find solutions to these.
High water pressures, combined with long power waterways, require careful management of water pressure during normal and emergency operating conditions. Rigorous design of the facility surge tanks, turbines and control systems will be required.
Constructing the huge underground cavern for the power station, about one kilometre below ground, also presents engineering challenges. The cavern fit-out includes six main transformers, weighing up to 250 tonnes each. Simply transporting the transformers down into the cavern will be a major logistical exercise.
We have already mobilised a world-class team of electrical and civil engineers, environmental experts and project planners as we move from the planning phase to a final investment decision.
Early results from geotechnical investigations have been favourable; the terrain is rugged and challenging, but manageable. We are examining pumped hydro projects around the globe to ensure Snowy 2.0 incorporates world’s best practice and cuttingedge design.
Snowy 2.0 will rely on proven and reliable pumped hydro technology that does not degrade over time – like the Snowy Scheme, which has endured for more than 60 years. Through technological upgrades and maintenance, it is in fact operating better than new, with an additional 300MW of capacity from when the Scheme was constructed.
Large investments such as Snowy 2.0 rightly attract public scrutiny. At Snowy Hydro, we are confident the project can be built, that it stacks up commercially and technically, and that it will be a key part of the solution for the need to balance security and reliability, affordability and reduction of emissions.
The Snowy Scheme was the realisation of a grand vision. It turned inland the waters of the Snowy River, providing irrigation to Australia’s parched interior and creating vast new supplies of green energy. Snowy 2.0 is our chance to build on the legacy of the pioneers before us.
Pumped hydro energy storage is a proven energy storage solution, and its future is bright as Australia seeks cost-effective, reliable options to make intermittent renewables ‘dispatchable’. Across the nation there are many thousands of potential sites, but how can a developer filter these down to the best few?
The challenges of transforming Australia’s energy sector now regularly dominate the nation’s news headlines – and where there’s a challenge, there are usually plenty of opportunities.
As Australia’s energy market progressively transitions from aging thermal generation to increasing amounts of wind and solar, there are ample chances to explore and develop the energy storage solutions needed to mitigate the challenges that may come with the introduction of more renewables into the energy market.
With increased intermittent renewables, we will require more storage to smooth out the variability of weather-dependent generation so that energy is available on demand. As well as this, we will need storage that provides the inertia, voltage and frequency control required for a stable, reliable grid.
The key to successfully embracing these energy storage opportunities will lie in identifying the right mix of technology, capacity and site; however, pinpointing potentially viable projects is complex. A theoretical or academic approach won’t be enough to ensure a future project’s success in the real world.
In terms of pumped hydro – a highly efficient, longer-duration solution with a proven track record – there are thousands of potential sites across Australia. This means that developers and investors need smart methods of filtering to reduce the many possibilities to just a few ideal sites.
A pumped hydro project is a major capital investment. Getting site selection right is the foundation for success, as it will determine the likelihood of achieving a design that is both technically and commercially feasible with the right mix of capacity and costs.
A head start in site selection
Specialist power and water consulting firm Entura has produced a practical atlas of pumped hydro energy storage opportunities to support development of dispatchable renewable energy generation across Australia’s National Electricity Market (NEM).
Through an exhaustive process, the atlas filtered many thousands of potential sites down to the best 20 around Australia. It is already being used by leading renewable energy company Hydro Tasmania to shortlist potential pumped hydro sites for the ‘Battery of the Nation’ initiative (a major Tasmanian initiative looking at how Tasmania could deliver more clean, reliable and cost competitive energy to Australia’s NEM).
Identification of promising pumped hydro sites through the atlas also offers opportunities for developers in states such as South Australia and Queensland, which have set ambitious renewables targets and must maintain energy security.
Entura’s Pumped Hydro Atlas of Australia takes into account far more than the basics of identifying ideal topography and a source of water. It also accounts for other practical factors that can make or break a project: such as proximity to and location within the transmission network, land use constraints and environmental risks, and the practicalities and costs of construction and ongoing operation. This makes it a real world, relevant resource identifying the best sites for pumped storage projects across the NEM.
Originally commissioned by Hydro Tasmania, Entura’s Pumped Hydro Atlas of Australia was completed in October 2017. The journey began with a literature review, appraising previous studies. This informed the development of a set of rules,
assumptions and algorithms for a GIS-based study of different reservoir types and pairing mechanisms, which were tested on pilot sites.
Using these algorithms, more than 200,000 pairing reservoirs were identified across the NEM states (Queensland, New South Wales, Victoria, Tasmania, South Australia and the Australian Capital Territory).
State-based heat maps of potential sites for pumped hydro development were prepared, along with a summary of all key characteristics for each pairing reservoir set, such as installed capacity, energy storage, distance from the nearest substation, gross head, approximate head loss in the waterways, and active reservoir volume.
A subsequent stage of refinement prioritised high potential sites in some states. This process took into account
greater practical detail, such as costings, practical engineering aspects, environmental approvals and risks, realistic high-level arrangements, proximity to other generators, and characteristics of hydrology and energy storage.
This stage identified more than 5,000 unique potential sites, which were then further refined with a set of rules to select the best pairing reservoir at each site. The approximately 5,000 sites were reduced to approximately 500 of the most attractive options: those with an average head of more than 300m with relatively short distances between the reservoirs.
This exhaustive refining process ultimately resulted in a shortlist of 20 promising sites across different states, with a desktop review of geology, high-level engineering arrangements and approvals requirements. For each site a map was prepared including locality, land use,
planning zones and key characteristics of the potential pumped hydro project.
The Pumped Hydro Atlas of Australia is an example of how applied hydro power engineering can be used to create practical outputs, which are ready to be applied in the real world. Overlaying the outputs of this atlas with any new wind and solar development across the NEM could result in opportunities to invest in dispatchable renewable energy generation hubs capable of replacing thermal generation assets as they retire.
Pumped hydro energy storage will no doubt play a major role in the development and expansion of networks powered by renewable energy – in Australia and around the world. As Australia’s electricity mix evolves, so will the economics of storage.
While forecasting revenue for storage projects in the Australian electricity market
is still somewhat uncertain, there are many opportunities in both the existing and emerging markets to guarantee project revenues to a level sufficient to satisfy a lender’s requirements. The opportunity for investors seeking a head start in this emerging market is now.
About the author
Mohsen Moeini is a Specialist Dams and Hydropower Engineer at Entura. He has 18 years of experience in dam and hydro power engineering, and has worked throughout the Asia-Pacific region. Mohsen was the Project Manager of the Kidston Pumped Storage Project Technical Feasibility Study. He also led the development of the Pumped Storage Atlas of Australia, which identified project opportunities across the NEM.
More than 100 years ago, Robert Frost’s protagonist made an infamous choice between two roads that diverged in a yellow wood. He chose the road less travelled and looking back ‘…that has made all the difference’. Yet Frost then observes that the roads had in fact been worn ‘…really about the same’. Perhaps he was pointing to the human tendency to look back from the future on the different roads we could have taken, aware that all choices have consequences.
A century on from Frost, I can find his famous poem online in seconds. The speed of technology has fundamentally changed the way we source information and make decisions. Frost today would check Google Maps, refresh his smartphone compass or GPS navigation app, and be halfway down ‘a right’ road in no time. The Pandora’s Box that is automation technology is well and truly open. There is no going back.
But just because artificial intelligence, robotics and autonomous vehicles are here, should we take heed of Frost? Will we look back in the future and understand now that we still have choices that will
by Miranda Taylor, CEO, National Energy Resources Australia (NERA)
While transitioning towards a low carbon economy, Australia’s energy sector is faced with balancing energy security, affordability and accountability. Here, Miranda Taylor, CEO of NERA, explores how the industry will be guided in this change by new forms of automation and digitisation.
ensure technology works for all of us, not just a few?
Australia and our energy sector certainly have a hard road ahead. Together we must come to grips with the confluence of tectonic forces including climate change, ubiquitous connectivity and the rising tide of automation and digitisation that is impacting on what we understand as economic growth, jobs, work and society.
This challenge however, is too often framed in a polarised way – either as a dire threat or instant saviour. The truth is technology is neither. It can unleash terrible consequences, but it can also create extraordinary opportunities. This should both excite and unite us to discover and make clear choices together.
The real difference between choosing our roads today and the choice made by Frost is not that we have technology to aid us, though we do, but that he made his choice alone whereas we must explore and choose our roads together.
So, more prosaically, what does all this mean for the automation of the Australian energy sector?
Australia’s energy sector is facing the challenge of balancing security, affordability and accountability while transitioning towards a low carbon economy, and this will be guided, for better or worse, by increased automation across all energy industries.
So first, let’s be clear about the supply side of energy. Despite the tendency for the energy debate to become zero sum – a dystopian old energy vs new energy constraint – the fact is Australia’s energy supply will remain varied.
The energy transition will be just that – a movement that includes some mix of gas, coal and hybrid solutions for at least the coming decades as renewables become increasingly economic and competitive, and form a substantial proportion of the supply market.
It is therefore imperative the traditional energy sector transforms in efficiency and waste minimisation and becomes low carbon. In this way, our journey towards a decarbonised energy future cannot occur without supporting Australia’s traditional energy resources sector and leveraging Australia’s global competitive advantage, existing infrastructure, assets and technology into a smart, high value and sustainable domestic energy sector that can reliably meet Australia’s future energy needs.
If this is Australia’s energy journey, then automation and digital technology are helping to steer the wheel. They are also the key to realising a more flexible, networked and integrated renewable energy market.
Building on the capital discipline and cost structure focus of recent years, the energy resources sector is now developing and accessing the talent and knowledge to find, adapt and apply digital and automation technologies. We see this today in leveraged smart networked assets, autonomous sensors, Artificial Intelligence, robotics, drones and remote operating vehicles.
We see where the industry is heading with advanced data analytics that optimise performance and productivity through the digital integration of people, assets/equipment plus open process control technology to maximise efficiency and reliability.
Elsewhere, the move to open process control platforms and away from proprietary technology owned by a few large technology companies who have kept the market closed will have significant implications for the supply chain. The disruption to the supply chain brought about by automation and digital technology will also be an enabler – creating huge opportunity for innovative Australian startups and SMEs, and for new partnerships between these SMEs and industry and researchers.
In a practical sense, the rapid penetration of renewable energy technologies is, on the one hand, being driven by societal demand, but on the other is enabled by new tech becoming increasingly commercial, competitive and affordable. In the sector’s drive to manage costs, achieve efficiencies and reduce waste, new
partnerships have already emerged, and this trend will continue as energy resources companies look to the future and diversify into technology organisations.
For example, microgrids behind the meter can be deployed onto remote sites both onshore and offshore, and the energy resources sector can utilise their remote site expertise and infrastructure to partner with renewables (wind, wave and solar energy) to hydrogen, including for export.
Some changes are relatively predictable to plan for – but not all. The operating landscape today is distinguished not just by phenomenal leaps in data and analytics, and the integration and optimisation of assets, systems and operations, but also by the quickening pace at which these leaps are occurring.
In this environment, the key strategies for survival include the ability to use data in smart ways with enhanced data analytics skills and capabilities to identify and apply solutions through agile and fast processes, and building trust with new innovation partners.
It is at this point the central point of collaboration around our autonomous future is most critical. The importance of bringing together researchers, the private sector and governments to work together, fulfilling important but distinct roles during the energy transition, cannot be overstated.
We could do worse than to heed the call from Professor of Quantum Physics and 2018 Australian of the Year, Michelle Simmons, who said;
"I want Australians above all to be known as people who do the hard things … Australia offers a culture of academic freedom, openness to ideas and an amazing willingness to pursue ambitious goals …. Australia is a great place to discover things. I am grateful for that Australian spirit to give things a go and our enduring sense of possibility."
Professor Simmons is helping put Australia at the forefront of what has been nicknamed the ‘Space Race’ of the computing era: theoretically solving a range of problems exponentially faster than the best-known algorithms running on traditional computer platforms or through digital technology.
Whilst it might take years for this technology to arrive on scale, the transformational change that it will bring serves to highlight the need for Australia to prepare and develop the core skills and attributes today to be able to adapt to whatever technological future comes.
Australia’s energy resources sector can learn from these examples. After all, we possess all the right ingredients to create a fair and inclusive automated energy future for all Australians - the willingness to explore, a culture of discovery, openness to new technology, rich diversity of resources, innovative researchers and expertise in operating in difficult environments.
Our way forward then should not be concerned with picking the road less travelled, or even the one well-trodden. It must be about making the journey towards a prosperous and more digitised energy future and getting there together.
SPEAKERS INCLUDE:
Ian Kay, Chief Financial Officer, Australian Renewable Energy Agency (ARENA)
Simon Kidston, Executive Director, Genex Power
Carly Magee, Partner, Foresight Group
Ian Kirkham, General Manager EPC & Solar Hybrid, Conergy
Andrew Dickson, Business Development Manager, CWP Renewables
John Smeltink, Large Scale Renewables, Clean Energy Regulator
Derek Chapman, Senior Commercial and Marketing Manager, Adani Australia Renewables
Chris Wilson, Director, Terrain Solar
TOPICS INCLUDE:
– Impact of policy on the Australian renewables market
– The economics of storage
– Case studies of recently announced projects
– Market outlook
– The future of large scale solar in Australia
ORGANISED IN PARTNERSHIP WITH SUPPORTING PARTNER
The most frequent causes of protection misoperations are setting, logic and design errors, caused, for the most part, by the increasing complexity of modern protection systems. Line differential protection is a case in point. To date, dedicated test plans and sequences have been created for every test set and every test case, all of which had to be calculated and evaluated individually. By combining the three core functions of the test process in a software package, OMICRON electronics is raising the security and dependability of system test results to a new level.
When commissioning a protection system, utilities always endeavor to test relays in a way that reflects how they will later be used in operation. Line differential protection fulfills its function using two or more relays that communicate with each other. The relays are distributed across various substations.
The testing of line differential protection under operational conditions, or as realistically as possible, requires the extremely precise time-synchronised simulation of a fault scenario at each end of the protected line, also referred to as an end-to-end test.
To date, a separate test sequence was created for each end of the line. In the facility, a phone call is made to a colleague at the opposite end so that the respective pair of test cases can be started at exactly the same instant. This methodology has stood the test of time.
However, what is evident is that the costs involved and the susceptibility to errors of this approach – in its preparation, execution and troubleshooting – are very high. This has led to the scope of the test being kept to a minimum and even avoiding end-toend testing altogether, relying instead on the self-tests carried out by the relays. But it is precisely the end-to-end test that guarantees that the protection is working securely, dependably and selectively.
An innovative solution has, therefore, been developed that enables this important test to be carried out at a reasonable cost while still satisfying the testing prerequisites.
The main purpose of an end-to-end test is to validate the communications connection. However, it can also be used as a system test.
Studies such as the NERC Study have shown that most protection misoperations are caused by incorrect settings, or
logic, or design errors. This is due to the complexity of the power systems and the increasing demands, resulting in an evergrowing number of protection and logic functions, not to mention relays.
A system test can be a great help in detecting the faults that can occur as a result. If a threshold has already been calculated incorrectly in the design, a conventional test is only able to check if the relay picks up at the incorrect threshold. This fault can be detected by simulating the power system while calculating the end-to-end test. If we calculate the test signals by simulating a fault at 70 per cent of the line, it is possible to validate whether the settings would in fact trip a fault at 70 per cent instantaneously.
To download the whole article, visit
www.omicronenergy.com/relaysimtest info.australia@omicronenergy.com
System-based protection testing – something new again? Yes, absolutely. This innovative approach makes it possible to check the correct functioning of the entire protection system and thus increase the testing quality. Instead of validating individual relay settings, RelaySimTest simulates realistic scenarios in the energy system to reveal errors in the settings, the logic and the design of the protection system.
Christopher Pritchard Product manager
Network companies face growing challenges managing their aging power transformers whilst delivering high network reliability at lower costs, with increasing customer expectations.
There is a rapid shift towards large-scale variable renewable generation and disruptive new technologies such as peer-to-peer retail trading, batteries and high-speed electric vehicle charging. Power transformers must operate reliably for several decades and withstand these rapid changes that significantly impact their loading.
Australia’s fleet of power transformers have already, on average, exceeded 70 per cent of their original design life of 30 to 50 years, depending on operating conditions and desired reliability. In the current economically-constrained environment, Australia’s regulators are demanding higher transformer utilisation and even longer lives with higher network reliability.
Distribution and transmission companies must respond to the regulator’s and customer’s demand by adopting innovative transformer lifecycle management practices and new condition monitoring technologies to assess and manage transformer failure risks and extend transformer life. This is a challenging task, requiring experienced staff equipped with innovative tools, comprehensive data and sound engineering judgement.
Low cost approaches are needed to gather essential data from aging transformers to including up-to-date measurements of oil impurities, partial discharges etc. Whilst online monitoring may be a theoretical option, it can be expensive and difficult to economically justify. A compounding factor is the difficulty in justifying the return on any investment in conditioning systems near the end of a transformer’s life when its residual value is quite low.
The network is changing. Transmission and distribution networks globally were designed to transfer electrical power from large fossil-fuelled generators to load centres. In Australia, these generators were located near remote low cost, coal mines, linked by a high-capacity transmission system to distant distribution networks.
In contrast, most new solar farms are being developed at the western and northern extremities of the grid where solar insolation is higher and land is cheaper. The existing grid in such areas has low capacity because of the sparse population. The network company is faced with the challenge of significant increases in network loading and its variability combined with minimal support for network reinforcements.
Australia’s regulatory framework requires shared network upgrade costs to be met by electricity users, other than dedicated radial connection assets which are funded by the new generator. Regardless, the network company must transparently justify investment in new assets.
Two new disruptive technologies are electric vehicles and transactive energy. Electric vehicles are on the cusp of becoming mainstream, with many of the global
auto-manufacturers releasing their plans for mass rollout in the very near future. High-current EV chargers will place a strain on the supporting distribution network, especially distribution transformers, reducing their residual life.
Transactive retail energy trading, commonly called peer-to-peer trading, will see households making greater use of the distribution networks to trade electricity. Low and medium voltage distribution networks have almost no monitoring because historically this was not required, there was only a traditional one-directional flow of electricity towards every house, and the large distribution networks were made cheap to simplify designs.
However, the introduction of rooftop PV and the new disruptive technologies will lead to higher bi-directional power flows on these networks overloading distribution transformers and causing transient overvoltages on LV feeders.
The increasing requirements to monitor the loading and condition of power transformers as well as increasing transformer utilisation and effective life will require new systems to gather, analyse and interpret asset data to improve asset oversight, and reduce the likelihood of unforeseen asset failures.
Online monitoring has been available for some time, however due to initial investment costs it has only been used on high value, high risk transformers. With falling costs and improving reliability many new monitoring technologies are being considered which can provide data on the condition of the transformer. However, this ICT infrastructure will require management by the utility, and then the usual considerations apply on keeping software updated and managing hardware obsolescence.
One strategy to reduce management costs is to keep the monitoring system as simple as possible, and use centralised computing for processing. Cloud-based software is becoming increasingly attractive to process the incoming data on transformer usage and condition to provide useful information on the assets, and there is now more focus on cyber security.
Research into transformer condition monitoring at the Transformer Innovation Centre has included the development of thermal models to understand the effects of short-term overloading on reliability and
residual life. The more detailed the mode, the more data is required and the greater the challenge to align internal business processes and decision making with the analytics and data.
Leaving aside the initial setup cost of data analytics, a 2016 McKinsey & Company report identified a 36 per cent saving in utility maintenance costs. Given that the Australian transformer fleet costs $200 million p.a. to maintain, the potential savings are significant. It is always best to focus on areas that deliver the ‘biggest bang for the buck’, which requires expert knowledge to identify.
The Australasian Transformer Innovation Centre (TIC) was set up with the objective of supporting industry to close the gaps between aging assets, new technologies and future needs of the network and stakeholders. Established in 2017 at the University of Queensland by a consortium of three universities and 19 industry members, TIC researches the transformer technologies identified by its members, and delivers industry-focused training courses on key aspects of transformer lifecycle management and practical condition monitoring.
The following four TIC research projects are already underway:
1. Resilience of networks using vegetable oilfilled transformers. Previous work suggested that power transformers filled with vegetable oil can be operated at higher temperatures than normal mineral oil. This work focuses on periods of extreme loading, such as during heatwave events, and how to maintain electricity supply to consumers
2. How asset management of transformers should change with the incoming wave of large-scale solar generation often located at the extremity of the network. Higher levels of harmonics may decrease the residual life of the existing transformers and asset owners must mitigate potential problems
3. Optimising techniques to measure partial discharge within power transformers to predict impending failure
4. Potential power quality problems caused by highcurrent power electronic devices that can affect power transformers
Three continuing professional development courses have already been developed since September 2017. The first one was a two-day introductory course on power transformer lifecycle management. The second was an advanced course on transformer bushing design, maintenance and operation. The third, which will be delivered on 27-28th June 2018, is an advanced course on power transformer tap changers: design, maintenance and retrofit. These courses are largely delivered by industry experts in addition to TIC university staff and all attendees rate these TIC courses as excellent.
For more information visit
www.itee.uq.edu.au/tic.
The world’s leading manufacturer for solar inverters, the SMA Group, has collaborated with Wilson Transformer Company to develop a range of innovative Solar Power Skids designed exclusively for the local Australian solar market.
Through this collaboration, both companies are committed to providing reliable and efficient solutions to their Australian customers.
The Power Skid Australia is an innovative product that incorporates a range of solar inverters and transformers, as well as MV and LV switchgear – all mounted on a fully bunded galvanised base.
This arrangement provides solar farm projects with a fully integrated, easily installed solution that is manufactured in Australia and supported by local teams of engineers and field support professionals. It also fully complies with all relevant Australian standards and is tailored to Australian conditions.
The Power Skid Australia was developed to serve the booming Australian solar market with a locally manufactured solution tailored to the specific conditions of Australian solar plants.
Manufactured in Wodonga in the state of Victoria, the solution minimises lead times, simplifies logistics, cuts installation and commissioning times, reduces risks and offers a robust high-quality solution packed with features, providing a full turnkey product for SMA’s customers.
This solution also provides jobs in rural Australia and supports the Australian economy by producing high-quality technologically advanced products.
The SMA Group is a global leader for solar inverters, a key component of all PV plants, and had sales of around €900 million in 2017. SMA offers a wide range of products and solutions that allow for high energy yields for residential and commercial PV systems and large-scale PV power plants.
To increase PV self-consumption efficiently, SMA system technology can easily be combined with different battery technologies. Intelligent energy management and digital energy solutions, comprehensive services and operational management of PV power plants round off SMA’s range.
The company is headquartered in Niestetal, near Kassel, Germany, is represented in 20 countries and has more than 3,000 employees worldwide, including 500 working in development. SMA’s multi-award-winning technology is protected by more than 1,000 patents and utility models.
Since 2008, the Group’s parent company, SMA Solar Technology AG, has been listed on the Prime Standard of the Frankfurt Stock Exchange (S92) and is currently the only company in the solar industry that is listed in the TecDAX index.
SMA is the largest integrator with Medium Voltage Systems sold as MVPS/UPSys and MVS in the IEC world and Medium Voltage Platform, Utility Power Rack and MV Block sold in the ANSI World. Since March 2018, SMA has partnered with Wilson Transformer Company in Australia to produce an Australian made integrated solution for 2500 and 2750kVA inverters.
WTC is the largest Australian-owned and based manufacturer of power and distribution transformers, operating from two manufacturing facilities in Victoria, and Support Service offices around Australia. WTC also operate offices in New Zealand, Singapore and the United Kingdom, subsidiaries in the United States of America and Australia, as well as joint ventures in Saudi Arabia, Malaysia, the Philippines and Israel.
Wilson Transformer Company has a successful history of providing transformer solutions for the renewable sector, particularly in the wind, solar and hydro energy projects.
Reference large projects include the replacement of seven large generation transformers in the Manapouri Hydro Power Station in New Zealand, some of the major wind farm projects, including Gullen Range, Ararat and White Rock, and the Australian Solar Flagship projects, including Broken Hill and Nyngan.
We are proudly introducing a new range of products to the local market. A fully integrated, easily installed solution for solar farm projects.
More details at www.SMA-Australia.com.au, 1800 SMA AUS, info@SMA-Australia.com.au, www.wtc.com.au
Cagil Ozansoy, College of Engineering and Science, Victoria University
Next February, Victorians will mark the 10th anniversary of Black Saturday, when bushfires ripped through the state of Victoria resulting in 173 deaths and billions of dollars in damages. Faults in electric assets were proven to be directly responsible for many of those horrific fires.
On the weekend of 17–18 March 2018, hot and windy weather once again swept through Victoria, causing bushfires in the south-west of the state. Emergency service officials and Victoria police reports suggested that the fires in Gazette, Garvoc and Camperdown originated from the same sources: vegetation striking power lines, or poles snapping and falling to the ground in strong winds. Thankfully, there were no human casualties that weekend, but the fires did destroy homes and killed many livestock.
At Victoria University, we have been developing a machine learning algorithm to detect occurrences when vegetation comes in contact with a power line. The key objective is to use this algorithm to intercept and cut the power supply to faulty overhead
power lines. If the ignition process of a branch can be interrupted in time (ideally within five seconds or less), the chances of a fire are significantly reduced.
The longer a branch burns, the more embers are produced that can fall onto the ground or get carried away by the wind. These embers are often what cause the fire to grow and spread. If vegetation conduction can be interrupted, there will be fewer or even no embers, reducing the chance of resulting flashovers, i.e an unintended electric arc between two conductors.
Our work drew on results from the Vegetation Conduction Ignition program, one of the several R&D projects funded by the State Government’s Powerline Bushfire Safety Program (PBSP). PBSP was established to identify cost-effective risk-reduction technologies and procedures to limit the risk of bushfires caused by faulty electrical lines.
In developing our algorithms, we examined a vast database of electrical signals that were produced from staged faults on diverse vegetation species under a range of scenarios to identify predictors that could be used in detecting vegetation faults.
With the use of renowned signal processing techniques, vegetation fault signature features were extracted and later used
In developing our algorithms, we examined a vast database of electrical signals that were produced from staged faults on diverse vegetation species under a range of scenarios to identify predictors that could be used in detecting vegetation faults.
in a machine learning classifier to discriminate fault states. These include the energy of specific frequency ranges and detection of particular time-frequency disturbances in the utilised signals.
The resulting study, High Sensitivity Vegetation High Impedance Fault Detection Based on Signal’s High-Frequency Contents, was recently published in the IEEE Transactions on Power Delivery journal.
The algorithm would ideally be embedded in a device connected to measurement equipment at various points on a network. It will first train itself with data from the measure point, and further discriminate disturbances as normal operation states, vegetation faults, or other problems. When a disturbance is detected, a sound decision can be made by the evaluation of the identified predictors. Fault signatures are the specific high frequency signal components introduced into electrical signals, during a vegetation fault.
The next stage of the project is aimed at developing a hardware prototype that can be installed in Victoria’s power networks before the next bushfire season. It will be able to quickly stop power supply to faulty sections of the network in the case of a vegetation contact, possibly saving lives and avoiding financial losses. We expect that once fully implemented, it could bring a stop to ‘branch touching wire’ faults from trees such as willows, identified as posing the worst fire risk.
Rapid Earth Fault Current Limiter (REFCL) systems are being widely installed in polyphase Victorian networks for this purpose. REFCL systems are expensive units, which can be out of service for extended periods. We believe that our methods can be used in conjunction with REFCL systems to add extra security to the system.
In going forward, a key challenge is to test the proposed algorithm in a real-life scenario, in a controlled environment, where vegetation faults can be staged to properly evaluate the performance of the proposed algorithm. We hope to strengthen our collaboration with utilities in going forward with that ambition.
The State Government’s Department Economic Development, Jobs, Transport and Resources co-funded the project with a $45,000 contribution. Dr Cagnil Ozansoy led the VU research team, supported by PhD candidate Douglas Gomes, who is studying under a Victorian Latin American Doctoral Scholarship, sponsored by the Victorian Government. Douglas is positive that the development of his team’s next generation technologies will find widespread use around the world, including in his home country of Brazil, which suffers from similar bushfires to Australia.
Network operators are under increasing pressure to maintain a large network of, at times, aging infrastructure across both urban and rural areas. Such activities make up a large part of a power utility’s operational expenditure, and funding cuts from both federal and state levels make it increasingly challenging for utilities to undertake adequate vegetation management works.
Vermeer Australia’s National Sales Manager for Environmental Equipment, Craig Baillie said, “The key to being able to provide adequate vegetation management works while working within the constraints of a tighter budget is finding a contractor with highly productive and versatile equipment that will enable them to get more done, quicker, while maintaining a high quality of work.”
Contractors with versatile equipment that allows them to take on a wide variety of jobs - including tree pruning, brush removal and hazard tree removal - will be able to increase their productivity and efficiency.
“Vegetation management around power assets typically requires the removal and processing of vegetation both large and small,” Mr Baillie said.
“This means equipment that is able to find a balance between these jobs will provide the most efficiencies. A machine that is too small will increase time and labour costs for larger jobs, and a machine that is too big can be overkill, with a downside of increased fuel costs and reduced site access.
“A machine such as Vermeer’s BC2100XL Wood Chipper is small enough to take on smaller jobs such as brush removal, while also having the capacity and power to take on larger jobs. The efficiency gain here is that it can deal with the larger bits of timber that smaller machines can’t handle,
Vegetation management is a critical element of a utility’s asset management strategy. However, with maintenance budgets being tightened in many cases, there is a need to find ways to reduce costs while still completing all necessary work to a high standard.
but smaller than a whole tree chipper, which may be too big to be efficient on small jobs.”
Designed for high volume processing, the BC2100XL features a 275hp (205.1 kW) Tier 3 engine, providing enough horsepower to meet jobsite needs, and the combination of the exclusive Vermeer SmartCrush feature and two horizontal feed rollers produce a theoretical 10,000lbs/4536kg of combined pulling force—enough to process large timber consistently.
Larger pieces of timber can also be fed directly into the chipper with the hydraulic winch which is able to lift up to 4000lb/1814kg logs directly onto the feed table.
The BC2100XL comes with a number of other features that help boost productivity and efficiency.
“Strain on vital engine parts is reduced by Vermeer’s SmartFeed system. This system monitors engine rpm and senses overloading, automatically stopping or reversing the rollers as needed. The rollers can even be turned independently to turn and re-feed timber at the required orientation.
“The SmartCrush system also helps to improve performance on jobs where larger material needs to be dealt with. This system is designed so that the upper feed roller will automatically increase down pressure on the material once it has been freely raised for four seconds—as happens when larger timber is fed. This allows the upper feeder to easily climb larger material before providing the pressure required to crush and grip the fed material, to enable maximum infeed force.”
When it comes to operator-centric design features, a 153.7cm feed table keeps the operator further from the chipper drum, and Vermeer’s bottom feed stop bar system offers additional protection. A radio remote control also allows operators to maintain control of the chipper while using a mini loader to load the machine, with the winch able to be raised out of the way hydraulically to provide better infeed area access.
“At the end of the day, vegetation management helps save lives, property and possessions from bushfires, and reduces the instances of blackouts. The good news is that taking the time to find the right contractor with the right equipment can actually reduce maintenance costs while maintaining the integrity of power assets.”
Aby Julian Turecek, Head of Assets, EnergyAustralia
Waste-to-energy technologies are helping to reduce waste and emissions, while also supporting the integration of renewables energy sources in the sector.
ustralia is making the transition to a new, modern energy system. The challenge for industry and government is making an orderly transition based on the best and cheapest mix of generation, both existing and new.
EnergyAustralia is the proud owner and operator of around 2,900MW of existing coal-fired power stations; but we struggle to make an economic case for new coal-fired technology in Australia.
We have a neutral view about the technology that will replace existing coal as a source of base load supply, so long as it supports the delivery of reliable, affordable and cleaner energy.
We see the future modern energy system in Australia comprising of solar, wind, demand response, pumped hydro, battery storage, baseload renewables and intelligent energy management options, supported by gas-fired generation. For example:
» We have permits for 1,000MW of new gas-fired capacity at Tallawarra near Wollongong, and Marulan near Goulburn, as well as additional gas generation investment opportunities in Victoria
» Our Australian-first seawater pumped hydro energy storage project proposed for South Australia is progressing through the project’s second phase of works, necessary to proceed to a final investment decision
» We signed agreements worth around $50 million to operate two utility-scale battery storage systems in Victoria
» We have committed to deliver around 50MW of demand response reserve capacity across New South Wales, Victoria and South Australia as part of AEMO and ARENA’s pilot program
We are progressing these options so we can have projects on the ground before 2022, on the basis that the National Energy Guarantee policy will be in place and supportive of these new investments.
EnergyAustralia’s Energy Recovery Project, located at the Mt Piper Power Station in New South Wales, is another good example of the thinking and innovation that will come to underpin a new, modern energy system in Australia.
It has great potential to help solve two big challenges we face in Australia: reducing waste that goes to landfill, and integrating new supplies of renewable energy into the system.
Last year, in partnership with specialist recycling partner Re.Group, and with the assistance of the Australian Renewable Energy Agency, we completed a feasibility study which found the project was technically feasible and economically viable based on consumption of 200,000 tonnes of refuse-derived fuel per year.
The project will take proven technology and practices from Europe and apply them within an existing power station in a showcase of Australian innovation. At the same, the project will reduce greenhouse gas emissions by the equivalent of more than 200,000 tonnes of carbon dioxide per year, and as mentioned, will mean there’s less need to develop new landfills.
The fact that it’s integrated into an existing power station that’s already connected to the national electricity grid – avoiding having to build dedicated turbines, generators and grid connection –provides an important advantage. Another advantage is the fact the project is at an existing industrial site, minimising the issues you sometimes get with greenfield developments.
In operation, the Energy Recovery Project could generate reliable baseload electricity for an additional 40,000 homes in New South Wales without having to burn additional coal. And if viable, energy recovery will create around 300 direct and indirect jobs during construction, and 16 ongoing roles in operation.
A final decision on the project is scheduled for 2019. If it proceeds, the Mt Piper Energy Recovery Project could make its first power in 2021. We think all the ingredients are there for a modern energy system that can deliver reliable, affordable and cleaner energy for customers. The challenge is planning; getting the right balance and mix of energy and doing it at least cost.
Energy Networks Australia’s biennial conference and exhibition is fast approaching. Don't miss your chance to network with leading thinkers and innovators in technology, service delivery and asset management, as well as policy and regulation.
As the only energy networks conference and exhibition in the Australian market developed by the industry for the industry, this is your opportunity to be part of this critical national conversation on the future of the energy grid.
The landscape for the energy network sector has shifted dramatically with major changes in technology, customer behaviour and regulation. Energy networks are leading the transformation of the grid into a platform for new products and services — empowering customers with new information, new tools and new ways to cut costs.
A new feature of this year’s event is two oneday forums designed for senior staff in critical operational areas. Each Network Operations Forum will consider the latest operational practices and technology in supporting the modern grid.
On Wednesday 6 June, the Internet of energy: data, security & network operations forum will take place. Exploring the topics of ‘Unblocking the value of IoT’, ‘Protected assets: energy and cyber security’ and ‘Asset information: energy data analytics’, participants will be addressed by a range of industry experts from Boston Consulting Group, PwC and IBM.
battery storage and solar energy firm Zen Energy by another Gupta family company SIMEC Group, and the purchase of the Tahmoor coal mine from Glencore, is intended to create Australia’s first fully integrated steel business.
Mr Gupta’s insights into energy intensive manufacturing in an age of renewables and intense competition will be a fascinating contribution to the Energy Networks 2018 conversation.
Plenary sessions will feature industry leaders from across the network sector including Nino Ficca (AusNet Services), Guy Chalkley (Western Power), Paul Italiano (TransGrid), Richard Gross (Ausgrid), Ben Wilson (Australian Gas Infrastructure Group) and David Smales (Energy Queensland). NSW Resources, Energy and Utilities Minister, Don Harwin, and Australian Environment and Energy Minister, Josh Frydenberg, will also address the conference.
Energy Networks Australia is delighted to welcome Peter J Peacock, Chair Customer Forum for Water in Scotland; Blanca Losada, Chief Technology Officer, Gas Natural and Chief Executive Officer Gas, Natural Fenosa Engineering; and Susan Kennedy, Founder and CEO, Advanced Microgrid Solutions, along with several other esteemed leaders in the field.
The concurrent program features more than 60 national and international experts who will discuss the key issues affecting Australia’s energy future. Speakers come from a range of energy sector businesses, leading service and technology providers and research organisations including Reposit Power, Landis+Gyr, Boston Consulting Group, CSIRO, Siemens, ABB, Flow Power and ARENA.
The ongoing challenge of Vegetation Management will be discussed by the second forum on Thursday 7 June. Speakers from member networks and suppliers including Intelfuse, GHD and ENSPEC Environment and Risk will share their experience on strategic approaches to vegetation management, technology and innovation, plus vegetation management operations.
Forum participants can register at a special one-day forum delegate rate of $880. These tickets give participants access to the day’s forum, plus full access to the exhibition hall and morning plenary session.
A prominent figure in this broader transformation is British entrepreneur Sanjeev Gupta, Executive Chairman of Liberty House Group. Energy Networks Australia is delighted to announce that Mr Gupta will deliver the conference’s keynote address on 7 June.
Mr Gupta heads a global enterprise with activities spanning steel and aluminium production, engineering, power generation, banking and commodities trading. A key part of the business’ success is its GREENSTEEL strategy, which the company is utilising to help revitalise parts of Britain’s steelmaking industry.
It is a strategy Gupta’s family companies recently introduced to Australia with the 2017 acquisition of the mining assets of Arrium Steelworks in Whyalla, South Australia.
This purchase, together with the acquisition of a majority stake in
Topics to be explored include customer engagement, asset management, energy network transformation, regulation and tariffs, microgrids, embedded generation, and metering and grid intelligence.
The Meet the Industry Breakfast will again be held in 2018, providing exhibitors and sponsors the opportunity to invite guests through the Exhibition Hall and to network with the sector. Exhibitors will also be welcome to participate in the conference sessions.
For more information on the conference program visit www. energynetworks2018.com.au. With a large number of delegates and exhibitors, this biennial event is your opportunity to stay at the forefront of a sector in the midst of unprecedented change.
Join the critical energy conservation and help identify solutions that will deliver value for consumers and network operators.
Tuesday 5 June to Thursday 7 June, 2018.
International Convention Centre, Sydney REGISTER NOW
Registrations are open for Energy Networks 2018 – Vision Critical. Visit www.energynetworks2018.com.au to download the program, register and view information on fees, accommodation and social functions.
Don’t miss out on your chance to be a part of the only national Conference + Exhibition focused on the energy network sector organised by the industry for the industry and its supply chain partners.
Industrial applications of energy storage systems are now about more than power reliability and durability, customers want a deep understanding of the cost of ownership and profit opportunities, tailored to drive efficiencies and gains from investment.
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Restore is a customisable energy storage solution for on & off grid energy storage applications. It comes inclusive of an intelligent all-in-one power and energy management system enabling most kinds of electrical power and energy flow. Restore solutions embraces many platforms for user interface and remote communication requirements, from the standard Local HMI, browser based, smart phone and tablet access for remote monitoring and diagnostics giving the user the autonomy to manage and maintain as required.
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