Energy magazine June 2022

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ISSUE 18 · June 2022 ·

How to get to

100% renewable gas by 2050 The mega project sending power

from the NT to Singapore

Electricity distributor lessons from the NSW floods




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ISSUE 18 · June 2022 ·

How to get to 100% renewable gas by 2050 The mega project sending power

from the NT to Singapore

Electricity distributor lessons from the NSW floods


CHRISTINE CORBETT TALKS AGL’S FUTURE Cover image depicts AGL Energy’s Christine Corbett for our exclusive feature on the company’s future ahead of the proposed demerger.

Published by

Monkey Media Enterprises ABN: 36 426 734 954 C/- The Commons, 36–38 Gipps St, Collingwood VIC 3066 P: (03) 9988 4950 F: (03) 8456 6720 ISSN: 2209-0541

Editor Imogen Hartmann Journalists Christopher Allan Lauren DeLorenzo Stephanie Nestor Mikayla Bridge Holly Tancredi Design Manager Alejandro Molano Designers Luke Martin Danielle Harris Jacqueline Buckmaster National Media and Events Executives Rima Munafo Brett Thompson Jacob Trad Marketing Manager Radhika Sud Marketing Associate Andie James Digital Marketing Assistants James Holgate Jackson Barnes Publisher Chris Bland Managing Editor Laura Harvey



ndoubtedly, one of the biggest topics amongst the industry at the moment is the proposed demerger of AGL Energy, which will be determined by the impending shareholder vote on 15 June. At the time of writing, billionaire Mike Cannon-Brookes has launched a campaign to topple the demerger and bring forward the closure of AGL’s coalfired assets. I had the opportunity to speak with AGL’s Chief Customer Officer, Christine Corbett (featured on our cover), who, if the demerger is successful, will step into the role of Chief Executive Officer of the retail arm of the two businesses. In this feature, we unpack what recent events mean for the future of AGL, and we explore what a demerged business would look like through Christine’s uniquely customer-centric lens. Much like the rest of the industry I’m sure, the Energy team is eager to see what happens, and we’ll be covering the events as they unfold. As well as this unfolding story, this issue covers a number of projects that are happening around the country, with transmission playing a big role in the energy transition. We look at Project EnergyConnect in South Australia and New South Wales, and the Western Victoria Transmission Network Project. Plus, we explore the Australia-Asia PowerLink, which is designed to combine the world’s largest solar array and battery with 5,000km of transmission, sending electricity from the Northern Territory to Singapore. One thing that continues to impress me about our industry is the dedication and fortitude shown during moments of crisis, especially with ever-changing climate conditions that wreak havoc on our environment, our communities, and particularly, our utilities. We saw this play out earlier in the year as Queensland and New South Wales grappled with extreme flood conditions that saw National Disasters Zones declared, with residents left stranded and powerless. In this issue,

we speak to New South Wales’ Essential Energy about what it was like being front-and-centre during the disaster as they share some invaluable lessons from the event. I’m pleased to see the calendar now stacked with a number of in-person events where we can get out and about, connect, collaborate and challenge each other. That said, I’ve found the virtual format that sustained events throughout the COVID-19 pandemic to still be an excellent way to stay up-to-date on industry dialogue, innovation and solutions in a more flexible way. Energy’s sister publication Utility will be hosting the landmark virtual event for the Australian utility sector, Digital Utilities 2022, from the 21–23 June. The event will focus on three major topics: future grids, engaging customers and cyber security. If you haven’t already, I highly recommend that you register at: https:// As always, I love to hear from you about what’s happening in the industry, whether it’s projects, research, challenges or opportunities. If you have a story that you’d like to share, please get in touch. Imogen Hartmann Editor

We’re keen to hear your thoughts and feedback on this issue of Energy. Get in touch at or feel free to give us a call on (03) 9988 4950.

June 2022 ISSUE 18



hree states to participate in T 12-month EV Grid Trial


70 million funding for TAS $ Green Hydrogen Hub



$11 million for WA clean energy initiatives


AEMO announces roadmap for NEM reforms


New grid-scale battery to be installed in QLD


SOO update: maintaining reliability E post-Eraring closure













10 W hat’s next for AGL? Christine Corbett talks demerger

18 M itigating the impacts of coal asset retirement in regional Australia

32 From the Northern Territory to Singapore: the Australia-Asia PowerLink

16 H ow to get to 100 per cent renewable gas by 2050

20 C reating waves: using market demand to promote ocean energy

34 Furthering second life batteries: the communication solution

24 D avid O’Hara: being a trusted partner means people are the priority

36 The distribution revolution

26 Unpacking Australia’s hydrogen forecast: policies, costs and exports 30 T he 4 biggest challenges of wind turbine maintenance


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38 ENERGY NETWORKS 38 Transitioning SA’s power system with Project EnergyConnect 40 Q&A: Western Victoria Transmission Network Project


42 SAFETY AND RISK MANAGEMENT 42 When disaster struck: electricity distributor lessons from the NSW floods 45 Remote management key to power line safety




52 A trusted partner for a major Australian infrastructure electricity project

54 V egetation management that’s ahead of the pack

AUTOMATION 56 Automated systems mark the future of electricity networks

46 INDUSTRIAL ENERGY 46 Meeting hydrogen refuelling infrastructure requirements 48 The industrial challenges of hurtling towards net zero 50 How energy workers can protect their kids’ health for longer

58 ASSET MANAGEMENT 58 G rid transformation engine: translating concepts into reality 60 E nergy sector asleep as CDR deadline looms

WASTE TO ENERGY 62 7 tasks for Australia’s bioenergy future

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lectric Vehicle (EV) drivers in Victoria, Tasmania and the ACT are participating in a 12-month EV Grid Trial looking at how home fast-charging technology can potentially reduce energy costs and electricity grid demands. Five electricity network businesses – Jemena, AusNet, United Energy, TasNetworks and EVOEnergy – together with charging infrastructure company, JET Charge, are partnering in the trial, co-funded by the Australian Renewable Energy Agency (ARENA). As part of the 12-month trial, ‘smart chargers’ have been installed at the homes of more than 160 EV owners in Victoria, Tasmania and the ACT. These smart chargers not only charge EVs up to three times faster than the chargers that usually come with the vehicle, but also allow electricity network operators to dynamically adjust when the vehicle charges. This means participants’ EVs can be plugged in when it’s convenient, but charged at times when the electricity grid has more capacity, whether that’s after midnight, or during the day when excess solar energy is being fed back into the grid – ideally leading to lower electricity bills for all consumers. Information about EV charging habits so far shows most owners plug in their vehicles to charge at around 6pm, already a time of high demand on the electricity grid.


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Electricity networks are also considering what they need to do to get ready for increased demand on the grid, with a $3.4 million ‘smart charger’ trial that kicked off 1 April 2022. Through the trial, participants will have more visibility of their EV charging data, and electricity network operators will gain a better understanding of how to work with EV owners to manage the increasing demand on the grid. ‘Solar soak’ events on forecast sunny days during the trial will allow participants to be notified ahead of time to have their cars plugged in during a day when there is an abundance of solar energy being exported into the grid. This will aid in better understanding the impact of EV charging in absorbing surplus electricity and helping manage grid voltage. Federal Government projections indicate EVs will be up to 30 per cent of all new cars sold by 2030, which would mean about 1.7 million electric cars on Australia's roads. The EV Grid trial is being led by Jemena, who has partnered with Victorian electricity distribution network businesses AusNet Services and United Energy, TasNetworks in Tasmania and EVOEnergy in the ACT. The trial has been co-funded by ARENA under the Advancing Renewables Program.





he Federal Government has announced $70 million in funding to turn Tasmania’s Bell Bay into a green hydrogen hub and unlock the potential for large-scale green hydrogen exports in the state. The green hydrogen hub will be part of the Federal Government’s expanded $464 million regional program and will maximise the opportunities for Bell Bay, and Tasmania, to be a leader in this energy source. The Tasmanian Government said it believes Bell Bay presents a perfect location for a nation-leading green hydrogen hub with its advanced manufacturing zone, renewable energy availability, advanced infrastructure, water availability and port access. The newly formed Renewables, Climate and Future Industries Tasmania, Government businesses, hydrogen proponents and hydrogen support partners, worked together on the Tasmanian Green Hydrogen Hub Project submission which was presented to the Federal Government in late 2021. The investment will have matching support from the Tasmanian Government working with Tasmanian GBEs and departments, with proponents paying their share of infrastructure costs. The renewable hydrogen hub is in line with the Tasmanian Renewable Hydrogen Action Plan which sets the goal of Tasmania as a globally significant exporter of green hydrogen from 2030. The hub is expected to establish the right environment and infrastructure necessary for operations to start unlocking the potential for large-scale green hydrogen exports and supporting domestic market activation in Tasmania and on the mainland. There is significant interest in Bell Bay from some of Australia’s largest potential hydrogen producers, including Fortescue Future Industries, Woodside Energy, Origin Energy and ABEL Energy.

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he Western Australian Government has dedicated $11 million for seven innovative clean energy projects through the second round of its Clean Energy Future Fund (CEFF). The CEFF will support regional projects that have the potential to support reductions in greenhouse gas emissions and create hundreds of jobs. The projects include solar, wind, biogas and biodiesel generation, battery and pumped hydroelectric storage, geothermal energy, and the replacement of gas with electricity to decarbonise the alumina refining process. The seven projects are expected to: » Invest $197 million, much of it in Western Australia » Create up to 255 jobs during construction and provide 63 jobs operational jobs » Generate 81,000MWh each year, enough to power 16,000 Western Australian homes » Avoid around 132,000 tonnes of carbon emissions each year, or 2.4 million tonnes over their design lives


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If the pilot projects are successful and technologies prove commercially viable, the seven projects could reduce emissions by 32 million tonnes of carbon dioxide equivalent in Western Australia. Project funding is conditional on successful completion of a formal funding agreement. The successful Clean Energy Future Fund Round 2 projects include: » » » » » » »

Frontier Impact Group’s Narrogin Renewable Diesel Project Power Research and Development’s Pumped-up Walpole Project Advanced Energy Resources’ Castelli Moora Microgrid Strike Energy’s Mid West Geothermal Project Alcoa’s Electric Calcination Project Metro Power Company’s AmbriSolar Battery Energy Storage System Project Alinta Energy’s Port Hedland Big Battery Project

The $19 million CEFF is administered by the Department of Water and Environmental Regulation, with support from Energy Policy Western Australia.





he Australian Energy Market Operator (AEMO) has announced the development of a roadmap to facilitate the approved post-2025 National Energy Market (NEM) reforms. As part of the Energy Security Board’s (ESB) integrated engagement to progress on the Post2025 market design, AEMO is leading the development of a ‘NEM Regulatory and IT Implementation Roadmap’. Towards the end of 2021, National Cabinet approved the ESB’s Post-2025 market reforms. The reforms seek to change the NEM design to enable the continuing provision of the full range of services to customers necessary to deliver a secure, reliable and lower emissions electricity system at least-cost. As part of the roadmap, AEMO will navigate the breadth of ESB reforms over the coming few years, de-risking delivery and informing implementation timing. AEMO Executive General Manager – Reform Delivery, Violette Mouchaileh, said, “The ‘roadmap’ will help avoid unnecessary or duplicative costs, and identify where strategic investments, such as IT systems and business processes, can be made to deliver efficient outcomes for AEMO, market participants and consumers.” AEMO will develop the roadmap with stakeholders through the Reform Delivery Committee (RDC).

Demonstrating a commitment to working transparently and collaboratively with industry, the RDC consists of nominees from the market bodies, NEM participants, consumers and representatives of the renewable energy, demand management and energy efficiency industries. Complementing its role with the roadmap, AEMO is also working with the ESB and its members, the Australian Energy Regulator and Australian Energy Market Commission, progressing reform workstreams and associated initiatives, including: » » »

Resource Adequacy Mechanism and a Capacity mechanism Transmission reform and congestion management mechanism DER Integration and the Essential System Services

Another workstream, data strategy, has been added, recognising the importance and value that digitalisation and data will provide to consumers, industry, operators and regulators during the transition of the energy system. AEMO is providing input into reform initiatives including data services, network visibility, bill transparency and data associated with electric vehicles.

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ublicly-owned generator CS Energy will install a 100MW/200MWh grid-scale battery in Queensland, aiming to provide clean and reliable energy to the state. The battery will be installed in Chinchilla, marking a step forward for the Western Downs Region as it plays a key role in Queensland’s renewable energy revolution. The 100MW/200MWh battery will be made up of Tesla Megapacks and form part of CS Energy’s energy hub at Kogan Creek. Treasurer and Minister for Trade and Investment, Cameron Dick, said the $150 million project was expected to create up to 80 jobs during construction and up to ten jobs when operational. “Queensland has the natural resources of wind, sun and water to be a renewable energy superpower,” Mr Dick said. “As we work towards our target of 50 per cent renewable energy by 2030, we can also support more jobs in new industries right across regional Queensland.


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CS Energy CEO, Andrew Bills, said the battery would be built next to Kogan Creek Power Station, providing its employees with exposure to new assets, training and skills as Australia’s energy sector transforms. “This project is about utilising the Kogan Creek site’s existing attributes of grid connection, water, land and workforce to create new opportunities,” Mr Bills said. “Large-scale batteries are an important next step in creating a more flexible and diversified energy portfolio for CS Energy and our owners, the people of Queensland. “Adding firm, fast start generation assets to CS Energy’s portfolio will enable us to more effectively respond to the changing demand and shape of the National Electricity Market.” The Chinchilla Battery will have a relatively small footprint (100m x 150m) and be connected to the grid via Powerlink’s 275kV Western Downs substation. Construction is expected to begin in late 2022 after all relevant development approvals have been finalised. The battery is expected to be operational in late 2023.





EMO’s update to the 2021 Electricity Statement of Opportunities (ESOO) report has found that the potential Eraring Power Station closure in 2025–26 will not hinder New South Wales' energy reliability if investments and projects remain consistent. AEMO’s Executive General Manager System Design, Merryn York, said the expanded assessments consider private and government-supported projects critical to improving reliability forecasts in the coming decade. Considering only existing and committed developments, AEMO forecasts an initial period of unserved energy (USE) above the reliability standard (0.002 per cent USE) in New South Wales, leaving reliability gaps of 590MW from 2025–26, 330MW in Victoria from 2028–29 and 770MW in Queensland from 2029–30.

To increase transparency and inform stakeholders, AEMO extended its reliability assessments based on various combinations of generation, storage and transmission investments not yet deemed committed under AEMO’s ESOO methodology. These forecasts are based on the ‘step change’ scenario developed with stakeholders for the Draft 2022 Integrated System Plan (ISP). This includes anticipated projects in AEMO’s Generation Information file and anticipated and actionable transmission investments, largely in the Draft 2022 ISP. A third case includes generation and storage targets considered in the New South Wales Government’s Electricity Infrastructure Investment Roadmap. Anticipated projects improve forecast USE in New South Wales to within the reliability standard in 2025–26. “New South Wales’ reliability will further improve following the completion of the

Sydney Ring (July 2027) and HumeLink (2026) transmission projects, which allows more southern New South Wales generation capacity, such as Snowy 2.0, to reach Sydney, Newcastle and Wollongong during times of supply scarcity,” Ms York said. Ms York said that the generation and transmission projects including the New South Wales Government Electricity Infrastructure Roadmap, are crucial to meeting reliability standards in the state by 2025–26. A further 138,000MW of proposed developments have not been included in any of the reliability forecasts, including numerous shorter-duration storage projects that may further improve reliability. AEMO will take updated commitments into account for 2025–26 in making its next reliability assessment in August 2022.

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It’s the topic that has dominated talk in energy circles this year – the AGL demerger. Energy sat down with Christine Corbett – the incoming Managing Director and CEO of a demerged AGL Australia – to discuss the demerger, her vision for AGL’s future, and her perspective on critical challenges in the broader energy industry.


GL’s demerger is designed to create two industryleading companies, each with strategies tailored to their individual purposes. Accel Energy will be Australia’s largest electricity generator, providing low-cost energy and driving the energy transition by repurposing its sites into low emissions energy hubs. AGL Australia meanwhile will be a leading multi-service energy retailer in Australia, supported by a sophisticated market trading function with access to firming, storage and renewable assets to help manage its energy portfolio risk. The proposed demerger would see Graeme Hunt, the current Managing Director and CEO of AGL Energy, step into the role as Managing Director and CEO of Accel Energy, while Christine Corbett, AGL Energy’s Chief Customer Officer, would move into the role of Managing Director and CEO of AGL Australia. Earlier this year, the demerger plans were thrown into the spotlight when AGL Energy received two unsolicited takeover bids from Brookfield consortium and billionaire Mike

Cannon-Brookes, which would see the pair acquire 100 per cent of AGL’s shares and close its coal-fired power stations early. The AGL Energy Board stated that both proposals materially undervalued the company on a change of control basis and were not in the best interests of AGL Energy shareholders. “Obviously, the consortium saw value in the business that we have and they saw value in the energy transition,” Ms Corbett said. “But we want to be able to unlock that value and share it with our shareholders, and the unsolicited bids and offers didn't create value for our shareholders. “The Board saw that it was in the best interests of shareholders to reject those bids and we've kept on with our number one strategy, which is the demerger.” Mr Cannon-Brookes then changed tack and came for AGL again in May, this time acquiring an 11.28 per cent stake in AGL shares through his family’s private investment group, Grok Ventures, making him the company’s largest shareholder. But concerns have been raised by a number of proxy advisers because his holding was gained through a series of swaps and derivatives, meaning partially borrowed stock can be recalled with three days' notice – the implication being that he does not have the same exposure to share price changes as other shareholders. Mr Cannon-Brookes made it clear in a letter sent to AGL’s board of directors that he intends to block the 15 June vote on the company’s demerger, which requires 75 per cent approval to go ahead. Mr Cannon-Brookes claims the demerger would lead to two weaker entities, which he claims will be more costly to run and delay the transition to net-zero. Instead, Mr Cannon-Brookes believes that by remaining one entity, AGL could begin shutting down its coal power generators and take itself out of coal power by 2030, in order to speed up the transition to renewables. AGL Energy said it has invited Mr Cannon-Brookes to share his plan for how this could be achieved without negatively

impacting shareholder value, customer prices and reliability but said Mr CannonBrookes has provided no such a plan. AGL Energy said, in contrast, it has spent more than 12 months working on its plan for the demerger and how both AGL Australia and Accel Energy will support Australia’s energy transition. AGL Energy stated, “It is a real plan, backed by real investment and a pipeline of real projects to lead Australia’s energy transition. Both companies will have investment grade credit ratings and will create a direct opportunity to invest in leading aspects of Australia’s energy transition.”

AGL: demerger is still best “The unanimous view of the Board is that the demerger is the best way to create shareholder value by allowing flexibility and a more focused strategic direction for each company moving forward, and providing clear pathways to low-carbon futures and tailored financial structures aligned to the profiles of each business,” Ms Corbett said. “We have a clear plan that will deliver the best outcome for our company, our shareholders and for Australia’s responsible transition. “This plan is backed by real investment and a pipeline of real projects to lead the transition, including a commitment to underwrite 3GW of renewables and flexible energy generation capacity by 2030, and a defined pipeline of 2.7GW of wind, battery, pumped hydro and low-carbon firming projects. “The Demerger Scheme Booklet gives our shareholders a clear and detailed plan for how we will accelerate Australia’s decarbonisation in a way that wouldn’t otherwise be possible. “The key part about the Demerger Scheme Booklet is that the Independent Expert has recommended that it is in the best interest of shareholders for the demerger to go ahead.”

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In the Demerger Scheme Booklet, the AGL Energy Board summarises that the demerger will provide four key advantages to its shareholders: unlocking value through the two separate entities and dividend policies; creating two industry-leading companies, within which shareholders can invest based on their value preferences; providing tailored purpose in individual strategies and initiatives; and enabling the future of energy through the responsible acceleration of decarbonisation. On the flip side, the disadvantages associated with the demerger include the one-off implementation costs of approximately $260 million, the additional ongoing operating expenses of running two separate entities, and the loss of scale and diversification. The AGL Energy Board maintains that the advantages of the demerger outweigh the disadvantages. “The Board considers that the potential for these additional costs can be offset by operating cost savings that AGL Australia and Accel Energy will have the potential to realise following the demerger, including technology cost reductions and reduced overheads driven by a more focused organisational structure,” Ms Corbett said. The Demerger Scheme Booklet also outlines the alternatives that were considered by the AGL Energy Board, which included maintaining the current business structure; accelerating coal-fired asset closure whilst maintaining the current business structure; an internal separation within AGL Energy; a partial or whole strategic sale to another buyer; or an Initial Public Offering (IPO). AGL’s proposed demerger would see Christine Corbett, AGL Energy’s Chief Customer Officer, move into the role of Managing Director and CEO of AGL Australia.



The AGL Energy Board said that, after considering these alternatives, it found that the demerger is “more likely to enhance value for AGL Energy Shareholders over the long term”, which was supported by the Independent Expert Grant Samuel. AGL Energy said that the transformation of its business will enable decisive action to better address its climate-related risks whilst taking the lead in supporting Australia’s energy transition, creating long-term value and sustainable investment opportunities at the same time. According to Ms Corbett, as the broader energy industry undergoes a transformation, it paves the way for businesses to do the same. “It absolutely is the right time to transform, to create a stronger future for two leading energy companies,” Ms Corbett said. “We've got two leading energy companies, two new strategies, two new purposes, and it allows us to unlock value and allows for our investors to participate in different ends and different sides of the energy transition story.”

AGL Australia: what would it look like? Ms Corbett explained that the proposed strategy for AGL Australia’s future is built on four pillars: 1. Customer obsession 2. Accelerating decarbonisation 3. Scaling up renewable energy investment 4. Engaging stakeholders (customers, community and employees) Ms Corbett said that the combination of these four pillars makes for an exciting challenge – one that she’s eager to get stuck into.

“We have a clear plan that will deliver the best outcome for our company, our shareholders and for Australia’s responsible transition.” “I'm really excited about our purpose, which is connecting every Australian to a sustainable future. We've got the brand, we've got the scale and those two things really give us a really exciting opportunity to accelerate decarbonisation – and we can do that with customers at the heart,” Ms Corbett said. Ms Corbett spent a large part of her career in executive roles at Australia Post, culminating in the position of Chief Customer Officer – the same title she currently holds at AGL Energy. This customer-centric skillset is one that Ms Corbett intends to employ front and centre if she moves into the role of CEO. Energy customers are unique, according to Ms Corbett, chiefly because of the historically low engagement and trust levels. This is something she expects to grow in importance, particularly with the electrification of the economy, wherein customers start to see energy in all aspects of their lives. Part of the challenge will be demystifying energy and sharing value with customers. Another foundational element of engagement lies in customer service and using digitisation as the vehicle for that.

“Customers expect to be able to get in touch with you any time of the day or night,” Ms Corbett said. “So how you digitise and use technology to make it simple and easy for customers is going to be important.”

The new prosumer profile The energy customer profile is changing as more and more consumers transition to prosumers. As the retailer-customer dynamic changes, AGL Australia will have to accommodate for the shift and ensure that it is still adding value. For Ms Corbett, the solution again lies in engagement – a strategy that she has seen play out in a similar way at Australia Post. Ms Corbett explained that previously, Australia Post was primarily a “letters business” with relatively low engagement from its customers until it transformed into a parcels eCommerce company – where much of the power was placed back in the customers’ hands. “As the customers were ordering, they wanted to follow and see where that parcel went. So we had to change technology systems, we had to change infrastructure. We had to change processes and we had to get customers engaged. It was a whole new strategy,” Ms Corbett said.



“I look at energy and it's really similar. You've gone from sort of a traditional utility, which is fairly ubiquitous, to all of a sudden understanding now you're a customercentric organisation.” With this engagement comes the opportunity for energy customers to really “lean in” and understand their own energy behaviour and usage. This in turn offers opportunities for businesses like the potential AGL Australia to identify the ideal products and services, like demand response programs and virtual power plants, that can service those growing needs.

Accel Energy: what would it look like? The big question around Accel Energy is how it would manage the closure of its existing coal-fired asset base, and achieve a balance of maintaining energy system security, while also keeping in step with shareholder and community expectations regarding coal exit. “Accel Energy has two key aims. One is to really understand and ensure the continuity and security of supply. That's really important given they're the largest generator in the National Electricity Market (NEM). So, it is absolutely about making sure that they can keep the lights on for Australia,” Ms Corbett said. “At the same time, renewable energy is going to be part of their future, so it's also really about making sure that there's a responsible, orderly transition from thermal hubs to low carbon industrial hubs. That's really the second part of their key strategy – it's looking at attracting different industries. “They've got a renewable energy pipeline of opportunities. That's part of their strategy as well, you can't be the largest generator in the NEM without making sure that you've got reliability, security and consistency, but you also need to transform – and that's what Accel will be doing.” To this end, early in May, AGL announced Global Infrastructure Partners as its 49 per cent equity partner in the Energy Transition Investment Partnership (ETIP), a $2 billion investment vehicle designed by AGL for Accel Energy to develop, own and manage an initial approximately 2.7GW of quality renewables and low carbon firming assets. These Foundation Projects will support Accel in maintaining its position as one of the largest operators and off-takers of renewable energy in Australia, and


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“We have said before that the transition needs to be managed in a responsible way – any other approach would have serious implications for electricity prices, grid stability and jobs.” to drive Australia’s energy transition by developing new renewable and low-carbon firming assets.

Flexible timelines for a responsible transition In terms of timelines for how quickly Accel Energy would exit coal, Ms Corbett said Accel has released closure “windows” to give the business the opportunity to bring forward the closure of coal-fired power stations if the system was ready and the market conditions were right. These windows also allow for policy changes, such as the Federal Government’s recent request to extend the generator closure notice period that energy companies should be required to give from 3.5 years to a minimum of five years. Ms Corbett said the windows that Accel has put in place would accommodate either notice period, therefore creating flexibility in the planning process for those assets. “We have already brought forward our coal closure dates, and we’ll be reviewing this every year should the system demonstrate it is ready even earlier for coal generation to close,” Ms Corbett said.

“If we can move faster in a responsible way, then we will. We have already closed the first unit at our Liddell Power Station, and we are on track for its full closure in less than a year’s time. Our work to transform the site into the Hunter Energy Hub is well advanced. “We have said before that the transition needs to be managed in a responsible way – any other approach would have serious implications for electricity prices, grid stability and jobs.”

What’s next for AGL? AGL’s Board of Directors remain confident that the demerger will proceed as planned; and Ms Corbett is particularly excited about the climate targets that the company would achieve if the demerger is successful. AGL Australia is set to be immediately carbon-neutral (scope one and two) on listing, and has a commitment to have 50 per cent overall reductions by 2030 based on FY19 levels, and being net zero by 2040. As for what she’d like to leave as her legacy as the CEO of a demerged AGL Australia, Ms Corbett is focused on the goal of seeing every Australian connected to a sustainable future. This circles back to the four pillars of the business – customer obsession, accelerating decarbonisation, scaling renewable investment and engaging stakeholders – as well as engaging employees and bringing them on the journey to achieving the mission. “People looking for work have more agency in that choice than ever before, and we’re in the fortunate position of having employees coming to us and saying ‘I want to work for a company where I can make an impact’ – and at AGL Australia you can make an impact. “Having a purpose that really resonates, with people being able to wrap their hands around it and say, ‘I can understand my role in bringing that to life’, that's amazing... it's a humbling, wonderful opportunity to lead an organisation that has that at its core.” As for AGL Energy’s future if the demerger isn’t voted through, neither party has confirmed what that will look like yet. Energy magazine will be covering the story as it unfolds on 15 June and beyond, so make sure to keep an eye out for updates at:


Christine Corbett plans to bring her uniquely customer-centric skillset into her incoming role as CEO of AGL Australia.

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HOW TO GET TO 100 PER CENT RENEWABLE GAS BY 2050 by Dennis Van Puyvelde, Head of Gas, Energy Networks Australia


Australia’s gas networks have developed a high-level plan to reach net zero emissions and are aligned on the need to decarbonise. All have made commitments to achieve net zero by 2050 or earlier. Meeting these targets will need coordinated action across many sectors of the economy. Energy Networks Australia and the Australian Pipelines and Gas Association have released a plan that details what is needed to reach these decarbonisation objectives.

as Vision 2050: Delivering the pathway to net zero for Australia – 2022 Outlook details what actions must be completed in the near term to achieve at least ten per cent renewable gas in networks by 2030 and what needs to be done for the transition to 100 per cent renewable gas by between 2040 and 2050. Blending hydrogen is already being undertaken in Adelaide and Western Sydney with more projects coming online on the west and east coasts in the next couple of years. High level roadmap to reach 100 per cent renewable gas by 2040 to 2050 Australia’s gas networks worked with DNV GL to develop a detailed action plan to achieve these decarbonisation goals. Both hydrogen and biomethane pathways were considered. Five tenets were agreed: » Customer Focus: Consumers today benefit immensely from cost-effective and convenient gas supplies, and rely on gas for a range of services, including cooking, hot water, space heating, power generation, and industrial heat and feedstock. The transition must support consumers in the residential and commercial, industrial, power generation, and transport sectors to decarbonise in a cost-effective and convenient way, keeping disruption to a minimum. » Safety: The high safety standards that exist for the current gas grid need to be maintained, through the development of the best technology and procedures for renewable and decarbonised gases across the Australian system, including the high-pressure transmission pipelines, the low-pressure distribution network, and end-user appliances.


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Security of Supply: A renewable and decarbonised gas network needs to maintain the existing high security of supply standards, with very rare unplanned interruptions, including by ensuring sufficient physical network capacity, efficient and safe system operation, and access to sufficient renewable and decarbonised gas production and storage capacity. Market Development: To achieve net zero, the gases in the network need to be certified as genuinely renewable and low carbon, enabling producers to produce renewable and decarbonised gases at a competitive price, with customer contracts forming the basis for the project and long-term operational financing, together with appropriate market incentives. Supply Chain: The supply chain and skilled workforce need to be available at the right scale and with sufficient agility to deliver the renewable and decarbonised gas transition on time, including the provision of enough appliances and other equipment, and to carry out the installations, connections, and asset upgrades safely and smoothly.

Cross-cutting actions The review of cross-cutting actions showed that good progress is being made with customer engagement and developing the business case for renewable gases. Work is underway to address the technical, environmental, and economic regulation requirements with the release of the papers on the reviews of the National Gas Law being noted as good progress in this regard. Market development is an area that requires further attention, especially in developing certification schemes, suitable incentives, or a renewable gas target.


Biomethane actions Biomethane is the renewably produced equivalent of natural gas. Blending biomethane into the gas network is already widely practiced in Europe, and rapidly progressing in Australia. The main advantage of this pathway is that no changes are required to pipelines, networks or appliances. Developing the biomethane pathway relies on supplying enough organic feedstock to replace the current volumes of natural gas.

Next steps Transitioning to fully renewable energy is a multi-decade process. The electricity sector started this journey in the early 2000s with the introduction of the Mandatory Renewable Energy Target. Renewable generation across the National Energy Market is currently at around 25 per cent with the intention of reaching 100 per cent by the 2040s – a total of more than four decades. Decarbonising the gas sector shouldn’t take that long. Early progress in renewable gas is creating a pathway to reach net zero emissions. But more support is needed to develop a renewable gas market. The introduction of a renewable gas target may just be the signal needed. Gas Vision 2050 can be viewed at

Hydrogen actions Reaching 100 per cent hydrogen in networks will be achieved in two stages. The first is to blend at least ten per cent into the network, followed by a second stage of conversion of the network to 100 per cent hydrogen. The main objective of the blending stage is about engaging with customers, building scale, and preparing for conversion to 100 per cent including assessments of infrastructure suitability, scaling up hydrogen production and developing a local manufacturing capability for hydrogen appliances. The second stage would involve making modifications to infrastructure to ensure safe operation, replacing natural gas appliances with hydrogen ones, and replacing the fuel in pipelines and networks with hydrogen. Introducing the right policy options at the right time will be important to facilitate that conversion, for example, enabling the introduction of hydrogen-ready appliances before the conversion is planned to take place. There are several hydrogen blending projects operational in Australia with more coming online. Many tests and studies have been completed to provide confidence that blending ten or 20 per cent hydrogen in gas networks can be done safely without adverse effects on customers. Reaching 100 per cent hydrogen will require additional focus on the supply of hydrogen appliances. There is an active and successful program to develop hydrogen appliances in the UK via the Hy4Heat program. Similar work needs to be accelerated in Australia to develop, certify and provide suitable appliances for the Australian market to enable conversion to 100 per cent hydrogen. Gas Vision 2050: Delivering the pathway to net zero for Australia – 2022 Outlook outlines the path to 100 per cent renewable gas by between 2040 and 2050.

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MITIGATING THE IMPACTS OF COAL ASSET RETIREMENT IN REGIONAL AUSTRALIA by Christopher Allan, Journalist, Energy magazine How might coal-reliant Australian regions find economic stability in a clean energy future? A new research report has analysed the challenges and opportunities that face South-West Queensland as it faces coal asset retirement. Here, we explore key insights from the research and look at the broader implications for energy transitions around the country.


ublished by Australian policy think-tank Blueprint Institute, the report, Breaking new ground: Challenges and opportunities of a changing energy landscape in regional Australia: South-West Queensland, suggests that with the right support, regions that have long housed Australia’s coal assets could absorb the challenges of a shifting energy landscape, and even capitalise on emerging sectors for regional job creation. With a focus on challenges facing South-West Queensland, the report models energy transitions around Australia, particularly in other regions facing coal asset closures and related issues of loss of local economic activity, a shortage in job opportunities, and even exiting migration from the region.


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The challenges of closing coal Stretching from the Simpson Desert to Toowoomba Range and encompassing communities like Chinchilla, Roma and Longreach, South-West Queensland has long served as a home to coal industries. But with the Australian Energy Market Operator (AEMO) predicting that coal-fired generators will retire two to three times faster than previously anticipated, completely disappearing from the grid by 2043, South-West Queensland will need a campaign economic renewal to mitigate this changing energy landscape. The report states, “For many decades, South-West Queensland has quietly prospered as a cornerstone of Australia’s agriculture and resource industries.


Although renewable energy presents economic opportunities, it will take considered policy to mitigate the loss of jobs exiting coal assets.

“Collectively, local coal assets currently employ over 1,500 workers directly and create opportunities for many more through indirect economic activity. “South-West Queensland is currently unprepared to deal with the rapid coal phasedown which is underway.” For example, in the community of Tarong, a township of 180 people, coal-related industries currently employ more than 15 per cent of the local workforce, and high wages from coal jobs have supported a variety of local businesses to prosper. “The projected closure of the Tarong coal-fired generator in 2036­–37 – though closure may come earlier as cheaper renewable energy alternatives enter the grid – will necessitate a proactive and efficient workforce shift to minimise the impact on the community,” the report said. In addition to loss of jobs and local economic stimulation, the necessary closure of coal assets can also result in crippling migration from small towns, with South-West Queensland already experiencing limited population growth. “Without action, this trend could accelerate into the kind of mass exodus seen in Spain’s former coal towns, as unemployed coal workers are forced to move to urban centres for low-paying, insecure jobs in service industries,” the report said.

Opportunities in renewable energy The renewable energy sector will undoubtedly help South-West Queensland adapt its economy to a changing energy landscape, with renewable projects offering both ongoing operation and maintenance jobs as well as short-term jobs in construction and installation. In fact, the report projects (conservatively) that incoming renewable installations will create 6,200 new jobs in South-West Queensland. A major Battery Energy Storage System (BESS) project in Tarong and the Kogan Creek renewable hydrogen demonstration plant will join existing renewable energy assets in the region, like Coopers Gap Wind Farm – Queensland’s largest operational wind project. The model finds that initial job figures from renewable projects match the employment base of the local coal industry. However, the report concedes that renewable energy job creation will skew towards shorter term positions created in the construction of major infrastructure. “It is unrealistic to expect the renewable energy industry alone to mitigate the inevitable loss of well-paying and stable coal jobs,” the report said. “South-West Queensland requires considered policy that seizes the opportunity contained in the initial surge of investment in renewables, and channels it into lasting opportunities that produce jobs in diverse industries in the long term.”

Emerging industries Some of the emerging industries with the power to support South-West Queensland’s economic revitalisation, alongside renewable generation investment, include clean industries and critical minerals mining. Clean industries Clean industries have already begun trials in South-West Queensland, with federal funding delivered for a methane demonstration project near Roma, and construction commenced on a hydrogen demonstration plant at Kogan Creek. “Though the initial employment figures for these clean hydrogen feasibility projects are modest, the success of these early studies could lead to enormous benefits in Kogan Creek over the coming decades if the plants are scaled up,” the report said. A hydrogen production facility at the Kumbarilla Renewable Energy Park, scheduled to commence in 2024, could create 144 short-term positions during construction as well as 480 ongoing positions to operate and maintain hydrogen production. Critical minerals mining Importantly, Australia’s clean energy future could offer a growth opportunity for our traditional mining industries. As the world’s largest lithium exporter and a major exporter of rare earth elements, Australia is entangled in global supply chains for construction of important clean energy assets like batteries, wind turbines and electric vehicles. “By 2040, between 5,400 and 9,450 (depending on policy action) new jobs in critical minerals mining are projected in Queensland, with the greatest concentration of known sites clustered around Mount Isa,” the report said. “While this would require South-West Queenslanders to relocate north, the close industry match could be a big advantage for those currently working in thermal coal mining.” A path forward The report concludes with recommendations for supporting the economic renewal of South-West Queensland in a changing energy landscape, including a suggestion for Federal Government to provide $20 million in funding to establish coal adaptation authorities in Groom and Maranoa. A coal adaptation authority would analyse the region’s shift to clean energy, investigate implications for regional residents, and engage with communities to develop strategies that respond to local concerns. It is also recommended that the Federal Government offer financial and administrative support to coal asset operators to develop proactive renewal strategies for exiting coal infrastructure. This could involve federal funding that matches private investment from operators, up to $100 million per asset. Another report recommendation is for the Queensland Government is to ensure that five per cent of collected coal royalties are directed to coal adaptation authorities – which would have amounted to $175 million in 2019–20. A further recommendation is that Queensland and local governments together maintain strong support for renewable energy zones and other new manufacturing and industrial precincts that will encourage investment into the South-West Queensland region. “The shift to a clean energy economy may not seem easy for those local communities in the region that currently rely on coal, but it can succeed,” the report said. “South-West Queensland possesses all the necessary ingredients to benefit from the future that is already knocking at our door.”

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OCEAN ENERGY by Stephanie Nestor, Journalist, Energy magazine

In Australia’s transition to renewable energy, there has been a heavy focus on pushing markets to take up new technology. A newly announced project from National Energy Resources Australia (NERA) and the Australian Ocean Energy Group (AOEG) endeavours to instead promote the adoption of ocean energy through market demand.

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ERA is supporting the AOEG to establish a world-first Integrated Ocean Energy Marketplace (IOEM) in Western Australia. The project aims to educate users about ocean energy technology and encourage its integration alongside other renewables. The IOEM was announced in May 2022 at the AOEG’s Market Summit in Hobart and a feasibility study has been launched to look into developing the project. The AOEG cluster, which was established with NERA’s support in 2018, is driving the IOEM, aiming to promote awareness, accessibility and affordability about ocean energy technology. Bringing ocean energy to the market AOEG Cluster Manager, Stephanie Thornton, said currently Australia’s energy markets are largely unaware of the benefits of integrating ocean energy with other renewables, including offshore wind. “We need to address this and raise the market’s awareness of the benefits of multi-purpose offshore energy parks that can optimise energy planning solutions as well as delivering low carbon solutions to marine based industries and communities,” Ms Thornton said. “Through the IOEM we hope to demonstrate our vision. We believe seeing leads to understanding and understanding underpins adoption. “This philosophy is at the heart of AOEG’s vision for the marketplace.” The project will have two stages – the first will be an online platform to help match end-users to energy solutions, and the second will be a pilot-scale offshore integrated grid system near Albany, Western Australia, to showcase these ocean energy solutions. The first stage The IOEM project’s first stage is a virtual marketplace and learning centre, which is intended to provide a forum for mutual understanding of the energy needs of endusers and potential ocean energy solutions. This digital marketplace will draw data from existing wave and tidal energy projects through simulation to mix and match end-users to proposed ocean energy system integrations and potential providers. NERA’s Ocean Energy Program Manager, Alex Ogg, said the first stage is an interim stepping stone to start the engagement between developing technology and market sectors for ocean energy.


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NERA’s Ocean Energy Program Manager, Alex Ogg, said Australia has excellent potential for ‘energy islands’.

“Our vision for the IOEM is a demand creation mechanism to bridge the gap and enable decision-making from end users by providing confidence in the products,” Mr Ogg said.

The second stage The second stage will be the construction of a physical marketplace in Albany, which will use an integrated microgrid to showcase ocean energy alongside other renewables and demonstrate the economic and social value of integrated offshore energy solutions. “While there are centres for testing a product development of ocean energy devices in Europe, the UK, Canada and the US, this will be a world-first ‘public’ market facing resource for ocean energy,” Mr Ogg said. “Technology agnostic, the IOEM will showcase how a microgrid based system can provide power to a typical blue economy end-user through an interactive platform.” The microgrid will include a combination of wind and wave energy converters, onshore and offshore solar, storage and application technologies such as green hydrogen production, desalination capability and electric vehicle (EV) charging. Alongside the microgrid, a database of ocean energy device capabilities will also allow potential end-users to understand the strengths of such a system, model their particular energy requirements, and find options which suit their needs. End-users will work with an associated project development partner to design, cost, procure and develop stand alone or integrated energy solutions for commercial applications.

Why ocean energy? With ocean energy being largely overlooked in Australia, market-users are unaware of the capabilities of tidal and wave energy. Ocean energy technology captures clean and reliable energy from the wind passing over the surface of waves or the currents caused by tides. When integrated with other renewables, ocean energy brings stability to the system by providing continuous power and reducing the need for storage or diesel back up. It can also help balance grids when other renewables, such as solar and wind, are not producing enough. Solar and wind can be intermittent due to weather conditions, whereas wave and tidal energy are more predictable and are able to fill in the gaps in supply, which is what the IOEM will showcase through its working integrated microgrid. Mr Ogg said AOEG is looking to the northern hemisphere for inspiration in this field. “We love the concept of energy islands which are being developed, particularly in France, Denmark and the Netherlands. They are simply amazing and will play a major role in future decarbonisation,” Mr Ogg said. “They’re literally an island, with a fully integrated energy system – ocean energy, solar and wind all connected to supply gigawatts of electricity. It’s something really exciting that’s emerging, and of course ocean energy is part of that. “In Australia, the resources are as good or arguably better. We could combine renewable offshore energy precincts with food production – supporting aquaculture, kelp production and blue carbon sequestration farms as an example.”


Concept of physical marketplace at Albany showcasing integrated ocean energy and renewable technologies. Image source: NERA.

From market awareness to market shift AOEG has identified four main focus areas to promote the adoption of ocean energy: 1. 2. 3. 4.

Building awareness Increasing accessibility Supporting affordability Establishing a project delivery system

The IOEM seeks to encourage the blue market sector in particular to adopt ocean energy through market-pull rather than technology-push. By making markets aware of ocean energy technology, the IOEM can encourage users to incorporate wave and tidal energy, while also promoting government funding in the area. In Australia, there are currently some wave farm projects in development on a pilot-scale, but the technology is not being pushed as much as other renewables. “There is low visibility and low confidence, with few or no commercial devices in operation in Australia and hence, no place to see ocean energy being produced,” Mr Ogg said. “There are also negative perceptions on the back of some early failures and a general perception that ocean energy is an expensive option.

“Because of low demand and the above dynamics, governments and policy makers have yet to prioritise the support of technical development, subsidies and blended finance options which would facilitate commercialisation and scale.” The IOEM will give visibility to early pilots and commercial projects, using this to leverage acceptance from the market and end users. Then, via visitation at the physical marketplace or online engagement, it will hopefully prompt government support and adoption.

Where to from here? To help turn its vision into reality, AOEG is currently seeking partners who can assist in making ocean energy a leader in the transition to sustainable and reliable energy. NERA CEO, Miranda Taylor, said the work done by the AOEG cluster to drive this technology-led and integrated energy project demonstrates the strengths of the cluster model in accelerating the commercialisation of technology and renewable energy solutions. “NERA helped establish the AOEG in 2018 because the evidence from around the world clearly demonstrates that clusters provide the business model to achieve market visibility, connect technology innovators with end-users and

drive more rapid innovation and business development,” Ms Taylor said. “The AOEG Cluster is facilitating the vital collaboration and innovation that is needed to ensure Australia achieves a net zero future and grows a strong offshore renewable sector, blue economy and diverse businesses.” Mr Ogg said the real challenge in the sector is identifying the customer, as most are not aware of ocean energy technology or how they can incorporate it into their systems. “We can see the opportunity, but as a tiny speck in the climate change discussion, acquiring the resources we need to do the job at the scale we need is currently elusive. When you don’t have leadership in government, business and communities sharing a similar vision, it feels like pushing a boulder up a hill,” Mr Ogg said. By using market demand to encourage adoption, the IOEM will focus on building awareness around the capabilities and benefits of ocean energy, giving users a chance to incorporate the technology on their own terms.

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DAVID O’HARA: BEING A TRUSTED PARTNER MEANS PEOPLE ARE THE PRIORITY The energy sector will rely on trusted partners to adapt to dramatic change during the next 25 years, and particularly valuable are those partners that won’t compromise on core objectives like the safety of people. As General Manager of Projects and Infrastructure at Zinfra, David O’Hara knows that the best way for leaders to navigate a period of change is to truly embody a clear strategy – one that speaks to long-term values like the safety of people and securing the right people for the job.


ince joining the Zinfra Leadership Team in 2020, David O’Hara has worked to promote a peoplefocused growth strategy that lays a healthy foundation for profitability across the entire organisation. Drawing on 15 years’ experience across management and engineering roles in industrial construction, Mr O'Hara has led cross-business initiatives at Zinfra that optimise project execution and delivery methodology – initiatives that have established Zinfra as a trusted partner for the future of the energy infrastructure sector. When it comes to fulfilling Zinfra’s role as a trusted partner to its customers in the energy industry, Mr O'Hara has found that a clear strategy, shared by all, can do wonders. “My view is that good strategies ought to be very simple, otherwise they’re not executable,” Mr O'Hara said. “If you try to tell a team of several hundred people a very complicated strategy, with lots of different components, you’re going to lose them after two or three minutes.” Mr O'Hara explained that while the Zinfra mission is to act as a trusted partner for the energy sector, the Zinfra strategy is very much focused on people and their safety, sharing a mantra of “Safety, then Profitability”. “Ultimately, to my mind, strategy is about achieving your objectives,” Mr O'Hara said. To demonstrate this, Mr O'Hara offered three key objectives that truly guide the Zinfra strategy: the objective of safety – to hurt


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no person; the objective of profitability – making a reasonable, sustainable, repeatable margin; and the objective of using the best people in the industry. For Mr O'Hara, being a trusted partner to industry flows naturally from the achievement of clearly defined objectives. “If your objectives are clear - if you keep it really simple like that and communicate it like that to everybody – then everybody knows what you’re about and can jump on the bus,” Mr O'Hara said. “In order to be trusted, we need to be able to deliver on the commitments that we’ve made. “Being a contractor makes this very simple, as your commitments are all listed down – it’s just about delivering all the time.”

The safety of people is our number one priority When expanding on the idea that a trusted partner needs to always put the safety of people first, Mr O'Hara revealed the far-reaching effects of this core value at Zinfra. “Safety is our number one priority, full stop,” Mr O'Hara said. “I have a firm view that it’s people who make a business safe, not systems. “You can override a system, but if your people have a safety mindset in them, you’re going to have a culture of safety, and a culture of thinking safety first every time.” In this sense, the strength of all systems actually flows on from a culture of safety first embodied by people and their decisionmaking.


Indeed, Mr O'Hara stressed that while safety is often at the forefront of contractors at projects in the field, Zinfra’s advantage is how safety first is recognised at an executive level. “We are fortunate enough to have a business at Zinfra where at every executive level – from managing director to myself, but also at the operations manager level and beyond that – everybody has a safety first mindset,” Mr O'Hara explained. “It’s printed on our shirts – every single Zinfra shirt has safety first written on it, and that is a value that we live and breathe every day.” Mr O'Hara knows first-hand the value offered by a culture of safety, drawing on 15 years’ work history that has taken him to major energy facility projects around the country in an Engineering, Procurement and Construction (EPC) capacity – from utility scale power stations, to wind farms and natural gas transmission facilities. “We have an executive and senior management team that is genuinely focused on safety and, by and large, has actually come from the field or has spent significant time in the field – and I’m included in that.” “I’ve seen what can happen if it goes wrong, but I’ve also lived and breathed and acted in high-risk activities as distinct from just looking down on it from the tower.”

Building an adaptable and connected workforce By delivering a growth strategy that focuses heavily on the best outcomes for people, Mr O'Hara understands how to truly build an adaptable workforce, from onboarding to career development. “Our onboarding process has matured enormously over the past couple of years, to the point that we now have a formal structured process with two days of training for all of our new starters,” Mr O'Hara said. “Some of this process is being implemented retrospectively, to make sure that everybody gets caught in the net. “It’s evolved into a multifunctional, multidisciplinary, interactive session that happens within Zinfra projects and infrastructure, to ensure that everybody has the same onboarding and training, and nobody has any gaps in their knowledge as they’re brought into the business from somewhere else.”

For Mr O'Hara, a socially connected workforce can be vital for improving work processes, staff mental health, and even empower staff to find the right role within the organisation. “What we find is that by hook or by crook, people tend to interact in person,” Mr O'Hara said, explaining that he encourages people to ensure they interact with others on a regular basis. “What I’ve found as restrictions have eased is it’s easy to forget how useful those incidental conversations can be and how much value can be generated from those. “I know it sounds nebulous or ill defined what that value means, but in terms of providing a solution in ten minutes instead of ten days of email exchange and misinterpretation – it makes an enormous difference.” For Mr O'Hara, encouraging conversations is also critical for staff mental health. “I’m focused on the mental health of some people who might be more vulnerable, ensuring that they have the opportunity to interact with people that could be avoidable by virtue of working from home – we get to a point where we ensure that everybody has interactions and we can keep an eye on one another as teammates.” Finally, Mr O'Hara has also found that a people-first growth strategy and a socially connected workforce can be vital for ensuring individual adaptability. “I often try to model how a career can develop and change,” Mr O'Hara said. “We do move people from place to place within the business, and also from function to function within the business. “And I consistently push the message to my team that if they want to seek an opportunity elsewhere in the business, then that’s something that I will quite happily facilitate, in particular if it’s going to make them a better leader, a better manager, a better functionary.” Mr O'Hara’s people-based growth strategy for Zinfra – grounded by values like safety first and the importance of communication – has set Zinfra up as a trusted partner for the energy sector, with clear successes including Zinfra’s well-established culture of safety and its socially connected, adaptable team.

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Due to emerging technologies, market factors and Australia’s federal priorities, there has been a huge surge of interest in positioning hydrogen as the fuel of the future. But what will the future of hydrogen actually look like?


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ccording to a PwC analysis, there are over 90 hydrogen projects in the works in Australia, with a collective, conservative estimate of over $250 billion in investment. There’s no doubt that the sector is widely seen as an opportunity to build economic growth, to establish export supply chains and to reduce emissions. The Federal Government has outlined the steps to make Australia’s hydrogen industry a major global player by 2030, with Australia’s National Hydrogen Strategy setting up the sector as a priority for investment and growth. But establishing the industry as a major global force is dependent on a number of constantly changing factors, such as production costs, transport costs, partnerships and regulations. Here, we look at how these factors are expected to change in the future, and what it will mean for the trajectory of hydrogen in both domestic and international markets. How much will it cost? Green hydrogen, which is created by splitting water into hydrogen and oxygen through electrolysis, produces significantly less emissions than fossil fuel-based hydrogen production. The good news is that with Australia’s abundant land and resources, we are well-positioned to produce globally competitive green hydrogen. The bad news is that currently, the cost of large-scale electrolysers is standing in the way of widespread production. But that is expected to change. A PwC Australia report, Getting H2 right: Success factors for Australia’s hydrogen export industry, anticipates a steep drop in Australia’s green hydrogen production costs by 2040 (see figure 1). In fact, green hydrogen is expected to become the joint-lowest cost fuel globally, becoming cost-competitive with grey hydrogen between 2030 and 2040. Year

AUD Cost per kilogram









Table 1: Australia’s forecast green hydrogen production cost (AUD/kg). Source: PwC Australia, Getting H2 right: Success factors for Australia’s hydrogen export industry

PwC Australia Integrated Infrastructure partner, Lachy Haynes, highlighted a number of factors which would help reduce the price of green hydrogen. 1


PwC report, Getting H2 right: Success factors for Australia’s hydrogen export industry

“To drive down the cost of hydrogen production, the industry must focus on overcoming the cost of large-scale electrolysers while continuing to drive down the price of our internationally competitive renewable energy,” Mr Haynes said. “Over the longer term, there is great potential for Australia to play a leading role in a globally traded hydrogen market. “Australia must put this opportunity at the forefront to demonstrate its intent and conviction in a green hydrogen future, or risk innovation and investment being deployed elsewhere.”

The factors driving cost changes As green hydrogen projects grow in scale around the world, confidence is expected to grow in financing improved manufacturing facilities for electrolysers. Increased investment in research and development of electrolysers, in addition to better access to equipment, is also expected to bring down costs of electrolysers, and of green hydrogen by extension. The Clean Energy Finance Corporation’s 2020-21 Annual Report shows that current electrolyser costs of $1.1 million per megawatt are expected to drop to around $500,000 per megawatt by 2050.1 Meanwhile, new technological developments are also expected to drive down electrolyser costs, with innovations in electrocatalysts and fuel cells increasing the capacity and efficiency of these systems. On top of these changes, a decrease in costs of other forms of renewable energy, such as low-cost solar and wind, will also drive down the cost of green hydrogen production. This is because electricity supply represents over half of green hydrogen production costs. Developers can look at reducing production costs by considering how to best size the electrolyser, the choice of technology and the best location for the project, where there is easy access to resources such as water supply and export infrastructure. Investing in export infrastructure As Australia’s hydrogen sector looks to prove its value in the global supply chain, investing in transport infrastructure will become increasingly vital. “For nations such as Japan and South Korea, who want to reduce their emissions but don’t have the renewable energy capacity domestically to meet those needs, importing green hydrogen is an increasingly attractive opportunity,” Mr Haynes said. “Other energy-rich nations are racing to capture this opportunity, so there’s no time to waste. We need a timely and robust regulatory framework that will give industry the confidence to develop the infrastructure, reputation, people and export pathways that will ensure we are globally competitive.” The location of the hydrogen project will greatly factor into transport costs, and project developers should consider whether transport costs outweigh the advantages of the selected location. The PwC report found that although the Federal Government’s seven priority regional hydrogen hubs all have access to port


infrastructure, further coordination is needed to reach the full cost-effective potential of hydrogen export infrastructure.

Adapting to new forms of hydrogen transport This coordination must cater for the major forms hydrogen exports can take, each with its own challenges and advantages. Liquified hydrogen, which is cooled to -253oC and transported in specially designed ships, is effective in that it does not have to be converted back to a hydrogen molecule once it reaches its destination. However, this form of hydrogen export requires costly infrastructure and technology to transport, and hydrogen boil-off can occur during shipping. Another common method is combining hydrogen and nitrogen to form ammonia, which can then be transported. Although transporting hydrogen in this form is much simpler in terms of the technology and infrastructure needed, it requires significant processing to extract the hydrogen from the ammonia once it arrives. When hydrogen is added to toluene, it becomes a liquid organic hydrogen carrier called methylcyclohexane, which can be transported at ambient temperature and pressure. This also requires significant processing to extract hydrogen once it reaches the destination, however toluene can also be captured for reuse in this process. Each form has different infrastructure requirements and associated costs. Emerging technologies, such as compressed hydrogen tankers, may also increase efficiency and reduce costs in the future. “For investors, the complex supply chain considerations for hydrogen projects present more challenges than core infrastructure assets,” Mr Haynes said. “Many hydrogen export projects currently under development have formed consortia bringing together the requisite industry knowledge, skillsets and delivery capability.” According to the PwC report, forming project consortia reduces construction, technology, market and offtake risks, and teaming up with credible export partners can bolster investor confidence. Policy challenges for hydrogen’s future infrastructure As Australia plans for a growing hydrogen sector, changes in its regulatory framework will be required to make the most of existing infrastructure and assets. “Beyond the physical infrastructure required across the renewable hydrogen value chain, it is the ‘soft’ infrastructure – in other words, the regulatory and social infrastructure – that is the binding ingredient to accelerate the uptake and growth of green hydrogen in Australia,” Mr Haynes said. Many proposals suggest using existing natural gas infrastructure to transport hydrogen and other renewable gases, and to blend biogas into those networks. However, the national gas regime did not account for this possibility when it was created, and thus amendments need to be made to allow hydrogen into current gas networks. In August 2021, Energy Ministers agreed to amend the national gas regulatory framework to include hydrogen, biomethane and other renewable gases.

The Australian Energy Market Commission (AEMC) has since released draft recommendations to expand existing gas market frameworks to spur further trade, investment and innovation. The proposed recommendations would: » Extend the economic regulatory framework » Extend market transparency with new Australian Energy Regulator (AER) gas price reporting functions, and further requirements of the Gas Statement of Opportunities, the Victorian Gas Planning Report and the Gas Bulletin Board » Adapt the Victorian declared wholesale gas market (DWGM) to include distribution connected facilities that can supply natural gas, low-level hydrogen blended gas, biomethane and other renewable gases » Enable consumers to be informed about the transition to natural gas equivalents » Allow new services to be priced and traded within retail gas markets » Streamline arrangements for short-term trading market AEMC Chair, Anna Collyer, said that these reforms were crucial to ensuring the safe and efficient delivery of hydrogen. “Hydrogen is one of a handful of new, low-carbon, zeroemissions fuels that can be used for heating and cooking in homes. Fuel cells can also power trucks, trains and cars,” Ms Collyer said. “In the future, the hydrogen sector may grow to include power generation and some industrial processes. Electrolysers that create hydrogen may also provide beneficial services to the electricity market, such as contributing to demand response and essential system services.”

Further potential policy changes PwC Australia’s report recommends four crucial steps for the continued development of a competitive and sustainable hydrogen industry in Australia. These steps include setting formal emissions targets to drive demand and further investment in renewable gases. Currently, Australia has set two priority stretch goals related to hydrogen – creating clean hydrogen production under $2/kg and building low-emissions steel production. According to the report, setting targets in the early stages of technology could help build momentum and certainty for private sector investors, as we have seen in Japan and the UK. Developing a Guarantee of Origin policy could enable better standardisation to compare different hydrogen products accurately, and provide consistency and transparency. A scheme for this is set to be released by the Department of Industry, Science, Energy and Resources in late-2022. Another step to take towards creating confidence in the sector is strengthening safety standards, particularly in hydrogen transport, to meet international standards. Finally, Australia will need to establish a skilled workforce to safely run advanced hydrogen applications, including engineers, technicians, safety officers, transport specialists, logistics workers and managers. This will require training institutions, governments and industry leaders to create the resources to reskill existing workers or develop highly specialised roles for the continued expansion of the industry.



THE 4 BIGGEST CHALLENGES OF WIND TURBINE MAINTENANCE Wind energy is well established in Australia’s renewable generation portfolio, with the nation’s meteorological and topographical factors lending themselves as excellent wind resources. With the Federal Government’s recent introduction of a framework supporting offshore electricity infrastructure, wind generation opportunities are only expected to grow. But, as with any rapidly adopted technology, wind power presents distinct challenges which have established themselves over time.


ccording to Geoscience Australia, the wind energy industry is “the fastest growing renewable energy source in many countries and is expected to continue to grow rapidly over the period to 2030”. Wind turbines present multiple challenges with regard to maintenance; they are tall, large and often installed in remote locations. As the technology shows no signs of slowing down, the tools and skills required to carry out turbine maintenance have struggled to keep pace. Although operators seek fast and safe maintenance, teams are required to work at height repairing or replacing heavy equipment, which is risky, difficult work. The challenges Here, we examine the four biggest challenges when it comes to maintaining wind turbines, and keeping wind farms operating at their best. We’ll also consider some of the unique solutions that have been developed to enhance the performance and life of wind farms around the world. 1. Yaw brake replacement The yaw component of a wind turbine facilitates the orientation of the wind turbine rotor towards the wind. The yaw brake secures the position of the nacelle upon re-orientation. The difference in yaw brake caliper weight can vary from 60-200kg. With some turbines, featuring up to 20 yaw brakes to control their position, this can place a substantial amount of strain on maintenance personnel, particularly given the scale of modern wind farms. In addition, many turbines lack in-built elevators, meaning maintenance personnel may have to climb a 100m-high ladder before repairs can even commence. 2. Resurfacing brake discs Yaw brake discs are typically large in size and weight, with the servicing of them previously requiring a total disassembly of the large turbine nacelle. Discs are prone to suffer wear as the turbine rotates to face the wind, with small imperfections growing and thereby compromising the smoothness of the disc surface. This can result in a deterioration of braking performance until failure occurs. Disc replacement cant be time-consuming, often requiring costly cranes which increase downtime and reduce energy output.


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3. Removing glazing to reduce noise A phenomenon known as ‘glazing’ can result in noisy wind turbine brakes, which can disturb both local residents and wildlife. When there is no wind and low usage, yaw brake discs begin to collect dirt, rust, and moisture as temperatures fluctuate. When the wind returns and braking begins again, this detritus is collected by the brake pad. Under high braking force, it is pressed tightly into the pad and disc surface, creating glazing. The result is a reduction in braking performance, compromised safety, and excessive noise, but unfortunately, once accrued, this glazing is difficult to remove. 4. Cleaning up yaw brake dust Braking systems produce harmful dust substances that present a contamination risk to the local environment, a challenge that has been a focus of the automotive industry for many years. The dust also poses a risk to maintenance personnel who come into close contact with it for an extended period of time. Large installations with multiple turbines require the careful selection of environmentally-friendly brake pad materials. The solutions Wind turbines’ return on investment (ROI) potential is dependant on their ability to operate reliably. Therefore, a capable and responsive global aftermarket service partner is imperative for maximising electrical output and safeguarding profitability of installations. Altra Motion has three decades of experience in wind turbine braking systems, and offers solutions to meet the needs of the entire wind turbine life cycle – with an emphasis on upgrading existing projects and equipment. Working in close partnership with original equipment manufacturers (OEMs), Altra Motion develops its products, components and assemblies to suit designs and specific requirements from the initial prototype phase. Products include the Yaw Brake Lifting and Installation Tool, which enables the easy interchange of yaw brakes in-situ; and the portable Disc Resurfacing Tool, which allows for uptower operations to be carried out on-site with increased speed while not compromising the refurbishment.

SPONSORED EDITORIAL FUTURE ENERGY When it comes to reducing yaw brake noise, Altra Motion’s Groove Tool cuts grooves in the yaw brake disc, acting like a razor as the turbine moves to meet the wind, cutting detritus from the brake pad. A brush located between brakes removes debris from the grooves, allowing the disc to clean itself, helping to safeguard braking performance. This solution is adapted to meet the specific needs of any given turbine. Specially developed in-house by Svendborg Brakes to develop an environmentally-friendly brake pad material, Altra Motion has created the Green Alternative Yaw Brake Friction Material. This product meets the restriction of the use of hazardous substances (REACH) standards adhered to by the automotive industry, ensuring that the environmental impact and risks to maintenance personnel from yaw brake dust are greatly reduced. In addition to its uniquely developed products, Altra Motion also ensures timely, responsive maintenance support via its 24/7, 365 days-a-year dedicated service app and phone number. Maintenance engineers around the world can message or call experts at any time to get access to key technical information and guidance for critical repairs, allowing Altra Motion to react quickly, leveraging innovative aftermarket service tools and solutions to solve issues fast.

For more information, visit:

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As more renewables are being injected into the grid, transmission is quickly being established as the vehicle for the energy transition. One promising project that’s combining both is Sun Cable’s $30 billion Australia-Asia PowerLink (AAPowerLink), which will include the world’s largest solar farm and battery storage facility, as well as a 5,000km transmission system. Energy magazine spoke with Sun Cable CEO and Founder, David Griffin, about the future of its marquee project and how this will transform the future of energy in the Asia-Pacific region.

he 17-20GWp solar farm and 36-42GWh battery energy storage located near Elliott, Northern Territory, will supply renewable electricity via 800km of overhead transmission lines to Darwin and then via a 4,200km undersea high voltage direct current (HVDC) transmission network to Singapore. The project will be capable of supplying 800 MW to Darwin and supply up to 15 per cent of Singapore’s electricity needs. Sun Cable has formed the Integrated Project Delivery Team (IPDT), a global consortium of industry leaders to deliver the AAPowerLink including Bechtel, Hatch, SMEC (a member of the Surbana Jurong Group), Marsh, and PwC Australia. The Federal and Northern Territory Governments have also granted the AAPowerLink Major Project Status and it has been listed on the Infrastructure Australia Priority List in recognition of its national strategic significance.


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Opportunities local and abroad Singapore’s highly-industrialised economy calls for low-cost, reliable electricity in order to facilitate long-term planning and economic competitiveness. Currently, Singapore relies on gas for approximately 95 per cent of its electricity generation. In order to improve this, the Singapore Energy Market Authority introduced a ‘Four Switches’ Policy, which seeks to increase renewable electricity imports. The Northern Territory Government is pursuing progressive renewable energy and economic targets of 50 per cent renewables and a $40 billion economy by 2030 (up from $26 billion in 2021). This presents significant opportunities to support local economic development while supporting decarbonisation. “The AAPowerLink will deliver jobs, education, and training opportunities for Territorians, including regional Aboriginal communities across the Territory.” Mr Griffin said.

For Mr Griffin, the inspiration behind AAPowerLink was borne from Australia’s unique solar generation potential. “Throughout my career of developing large-scale solar and wind projects in Australia and South Africa, I have always been astounded by the scale and quality of solar resources that exist in Australia,” Mr Griffin said. “This resource, matched with the immense electricity needs of the AsiaPacific region, presented an enormous opportunity for Australia to be a renewable electricity export superpower. “In 2018, it became apparent that technological developments and commercial progress of three technologies had reached a point whereby it was technically and commercially viable to transmit renewable energy on an intercontinental basis.” Mr Griffin said these developments include: » Rapidly falling solar PV costs and improved efficiency


Sun Cable’s AAPowerLink will supply Darwin and Singapore markets with reliable and competitively priced renewable electricity.

» »

Low-cost energy storage The ‘silent evolution’ in HVDC Transmission Technology, including HVDC Subsea Cables and Voltage Source Converters

“This realisation led me to establish Sun Cable, with the AAPowerLink as our marquee project.” Mr Griffin said.

Australia’s export power “Australia has been an energy exporter for many decades,” Mr Griffin said. “The AAPowerLink will enable energy exports for the 21st century, in the form of a new renewable electricity export industry, allowing supply to high demand markets in the Asia-Pacific region. “This will support regional neighbours as they undertake the energy transition and simultaneously bolster green industrial economic development. Further, it will open significant renewable energy supply chain opportunities.” Mr Griffin said Australia’s ability to export renewable energy will be possible through a multi-pronged approach, making use of HVDC subsea cable transmission, green hydrogen and other energy carriers – with grid interconnectedness at the heart. Challenges of grid interconnectedness Mr Griffin said Sun Cable’s vision is for an interconnected electricity grid throughout the Asia-Pacific region, which connects renewable energy resources from where they are most abundant (Australia) to where they are needed.

“The concept of grid interconnection is not new and the technology is well established and proven. In Europe there are 400 million electricity customers connected across 26 countries. They have already reached ten per cent interconnectedness and are aiming for 15 per cent by 2030,” Mr Griffin said. “Grid interconnectedness is still nascent in the Asia Pacific region. We are working to increase awareness of the importance and benefits of grid interconnection.” Sun Cable’s research and insights has estimated that if the Asia Pacific reached 15 per cent grid interconnection by 2040, there would be: » 3,000TWh, US$500 billion of electricity traded » US$120 billion investment in transmission » 900,000 total jobs created » 3,000Mt CO2e per annum abated

$210 million capital raise In March 2022, Sun Cable completed a $210 million Series B capital raise, contributed to by billionaires Mike CannonBrookes and Andrew Forrest, to fund the development work of the project and to accelerate the progress of the company’s portfolio of multi-gigawatt generation and transmission projects. “Sun Cable is grateful that all of our shareholders have continued to support the company by investing again in our recent Series B capital raise,” Mr Griffin said. “Their ongoing support validates Sun Cable’s strategy.”

First, but not last, of its kind The AAPowerLink is currently in the development stage. Once financial close has been reached, construction of the AAPowerLink will begin. “Through developing this project, Australia and the Asia-Pacific region will experience substantial growth in technology, skills, and supply chain benefits,” Mr Griffin said. “These developments will significantly increase Australia’s capabilities to export renewable energy to Asia, unlocking its latent potential.” According to Mr Griffin, the scale of the AAPowerLink will drive significant investment in manufacturing and incentivise R&D to increase efficiency, reduce risk and innovate, while its replicable IP design will support more projects in meeting energy demand. In addition, as scale and innovations reduce the cost of renewable electricity, the international competitiveness of alternative green energy carriers such as green hydrogen, ammonia and green aluminium are expected to rapidly increase, driving production volumes and demand for renewable electricity. Mr Griffin said the Australia-Asia PowerLink is a pioneer project that will provide a pathway for a sustainable and connected Asia-Pacific energy system.

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THE COMMUNICATION SOLUTION As the demand for renewable energy grows, more companies are searching for stronger and more efficient ways to provide green energy. Battery Energy Storage Systems (BESSs) are one way that energy companies are working towards increasing renewable energy supplies and having them readily available when needed by consumers.


onnected Energy, a builder and operator of second life BESSs, had been searching for a communications partner and system to incorporate within its E-STOR BESS, with a purpose to better enable thousands of Electric Vehicle (EV) batteries to be aggregated, controlled, and reused and thus, create second life batteries. Second life BESSs extend the life of EV batteries in industrial and commercial-scale, stationary energy storage systems. Not only is using recycled or second life batteries reducing the disposal issues of the financial burden, but also reducing the environmental cost of doing so. By 2030, a million tonnes of EV batteries are expected to be available for reuse. Global requirements for stationary energy storage could be completely met by second life batteries by 2035. The communications answer HMS Networks’ Ixxat brand is set to play a major part in some major, innovative, green energy projects, having been selected as a communications solution partner by Connected Energy.


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Connected Energy is using HMS Network’s Ixxat CANbridge NT 420 to bridge its technologies together and allow for stronger communication between the batteries and its management systems. Head of Supply Chain at Connected Energy, Jonny Cogman, said it is pivotal that as many Controller Area Network (CAN) channels as possible are available for communication. Mr Cogman said HMS’s CANbridge was not only suitable to incorporate within its E-STOR systems, but was ideal for its second life battery goals. “We retain the OEM battery management systems (BMSs) for each of the individual second life batteries that we fit into our E-STOR systems,” Mr Cogman said. “This means we can communicate with each battery, as and when required, and collectively the BMSs create the foundation layer of the system’s overall control system. “Reusing the existing BMS, giving them a second life also, maximizes the ‘green’ credentials of the E-STOR brand.” The BMSs use CAN bus for sending and receiving control signals, reflecting their origins in the automotive sector. Connected Energy’s technology has been proven, commercialized, scaled-up,

and installed in the UK, Belgium, Germany, and the Netherlands. The biggest system currently in operation is 1.2MW, but this will be surpassed in 2022 when several multiMW schemes are expected to come online.

Finding the right solution “There are many CAN solutions available on the market and we reviewed several before choosing to standardize on the Ixxat CANbridge solution from HMS Networks,” Mr Cogman said. “The deciding factor was that it proved very easy to program, but other benefits include that it is easy to install, while its robust build means that its long-term reliability is ensured. The longevity is particularly important because the life expectancy of an E-STOR installation is measured in years and decades.” CAN uses a serial, message-based protocol to minimise the amount of heavy and expensive copper wire used in vehicles. This means signals to and from each BMS are all sent along the same wires, or ‘bus’, with each signal having a header to identify it and keep it distinct from other signals.


Importantly, high-priority signals take precedence over less critical ones on the bus, so that there is always an immediate response for functions such as braking and turn signalling. The E-STOR control system architecture uses an Ixxat CANbridge NT 420 for interfacing with the batteries, then steps up through layers of intermediate control using Modbus to the central (EMS) or overall controller. This manages the installation’s functional operations so that it can be switched in and out in response to demand, supplying power when needed and recharging when there is surplus power in the grid. Furthermore, the transmission of data such as temperature, voltage and current is done in this way. “Our early installations were quite modest, typically 60kW, but everything was designed so that over time we have been able to scale up to megawatt systems and are now working on utility-scale projects,“ Mr Cogman said.

“The flexibility and adaptability of the Ixxat CANbridge NT 420 has let us design a control system architecture that is suitable for our range of installations.”

CAN vehicle applications CAN was originally developed for onboard vehicle applications and allows the many microprocessors fitted to modern cars and other vehicles to communicate with each other’s applications without a host computer. It has also become a popular choice for other non-automotive applications, including general automation, motorized prosthetic limbs, electronic gear changes on sports bicycles and emerging fields such as EV charging stations. HMS Network’s CANbridge solution’s easy-to-install functionality and robust build mean that it provides long-term reliability for E-STOR systems, making it a critical element for EV second life batteries and furthering the development of renewable energy sources.

For more information on Ixxat’s solutions, go to:

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THE DISTRIBUTION REVOLUTION Bushfires, extreme weather events, peak holiday periods, as well as being at the end of the network has put pressure on the power supply of the popular holiday destination Bawley Point, increasing the frequency of power outages. In response, Endeavour Energy is looking to future-proof its electricity network by fast-tracking an $8 million initiative to build the first community microgrid on the New South Wales South Coast.


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olunteer firefighter, Hendrik Boone, knows all too well the impact of power outages on his local community. A reliable source of power is critical to Mr Boone’s role as the captain of the Bawley Point Rural Fire brigade. Mr Boone was one of hundreds of heroic volunteers who saved the popular coastal town of Bawley Point on the New South Wales South Coast from the devastating Black Summer bushfires of 2019/2020 which destroyed thousands of homes and nearly 5.5 million hectares across the state. Because of the frequent power outages in the area, the fire station has installed back-up generators to ensure everything works when it’s needed. “If we don’t have reliable electricity supply, then we can’t open up the doors of the fire shed and get to the fire trucks – it is that critical,” Mr Boone said. Funded with the support of the New South Wales Government’s Bushfire Local Economic Recovery Fund, along with innovation funding, Energy’s initiative will see the edge-of-grid coastal towns of Bawley Point and Kioloa, just south of Ulladulla, become the centre piece of the energy distributor’s first community microgrid, providing a reliable, renewable, and stand-alone power supply during network outages. Announcing the initiative in early-2022, Endeavour Energy donated the first battery to be installed at the Bawley Point fire station, in a move Mr Boone believes will be a game-changer for his community. “This is a great initiative which will enable emergency services, residents and local business operators in the area to have a reliable power supply,” Mr Boone said. “Our food in the fridge won’t spoil, we will still be able to turn lights on and have hot water when we need it.” Endeavour Energy Chief Asset and Operating Officer, Scott Ryan, said the Bawley Point and Kioloa community microgrid would showcase modern grid technology. “Microgrids are a key part of the resilience story for regional, rural and urban communities – it’s using future grid technology to answer tomorrow’s questions right now. There is no time to waste and it’s absolutely critical we implement renewable solutions now,” Mr Ryan said. “The Bawley Point and Kioloa community microgrid is a key milestone in the revolution of the distribution of energy by addressing power reliability while accelerating the uptake of renewable energy.” Mr Ryan said a key objective of the initiative was working with the local community to co-design the microgrid. “Through a program of community workshops and meetings we are listening to the community and understanding their needs so we can build this together,” Mr Ryan said. The community microgrid will be a local energy system that draws electricity from renewable sources such as solar panels and batteries. While it is connected to the main electricity grid, it will be able to operate independently during outages, providing a consistent power supply to residents. The area of Bawley Point and Kioloa is currently serviced by two 11kV distribution feeders from the Ulladulla zone substation, around 38km away on the edge of Endeavour Energy’s operational footprint. Over time, power reliability has been improved through enhancements to the existing electricity lines in addition to a 1MW diesel generator. The proposed Bawley Point and Kioloa community microgrid, which is expected to be operational by mid-2023, will include the decommissioning of the diesel generator and replacing it with a 3MW grid battery which will be connected to a network of household batteries and solar panels.

Bawley Point Rural Fire Brigade captain, Hendrik Boone, receiving the first battery for the Bawley Point and Kioloa community microgrid from Endeavour Energy, CEO, Guy Chalkley.

To help manage electricity through the microgrid, state-of-the-art software will forecast the renewable energy load and manage it across all the solar panels and batteries, in real time. Households who participate in the program will be able to generate solar for their own immediate use, store it for later and share it back with the grid when the electricity network needs it. According to Mr Ryan, the Bawley Point and Kioloa microgrid will help demonstrate the benefits of harnessing microgrid technology to other communities. “The Bawley Point and Kioloa community microgrid is a great example of the distribution revolution taking place right now in the electricity landscape,” Mr Ryan said. “This initiative empowers customers and communities to manage a reliable and renewable power flow when they need it. It’s a win for customers, the environment and the network.” In creating a resilient energy community, Endeavour Energy is also working with the Shoalhaven City Council to convert more than 170 streetlights to smart LEDs that will deliver more efficient energy usage and allow the community to keep the lights on, even when disconnected from the main network.


Fewer and shorter power outages More choice and control over how energy is consumed Reducing carbon emissions More resilient power supply Reliable, affordable, and renewable energy for customers

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WITH PROJECT ENERGYCONNECT by Ralf Riccardi, Project EnergyConnect Project Director, ElectraNet

Australia’s energy landscape is changing, with renewable electricity sources displacing traditional generation. Renewable energy sources have become the largest source of generation in South Australia, with more than 60 per cent of the state’s annual electricity demand met by these sources. Transmission projects like Project EnergyConnect will be integral to the successful transition of power systems.


s South Australia continues its uptake of renewable energy, the state’s transmission network is playing an increasing role in managing two-way power flows and sharing power between regions to where and when it is needed. Project EnergyConnect, the new high-voltage interconnector between South Australia and New South Wales, is a central feature of the roadmap for the transition of the power system developed by the Australian Energy Market Operator (AEMO) in its 2020 Integrated System Plan (ISP). The South Australian component of the project is being delivered by ElectraNet, the owner and operator of South Australia’s electricity transmission network and the New South Wales component is being delivered by TransGrid. The primary purpose of the new interconnector is to enhance system security, provide net market benefits and support the transition of the energy market to a lower carbon emissions future. The infrastructure Project EnergyConnect involves the construction of a new 900km, 330kV transmission line connecting Robertstown in South Australia to Wagga Wagga in New South Wales, with an added connection to Red Cliffs in Northwest Victoria.


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The South Australian component includes a new 200km double circuit line in both 330kV and 275kV from Robertstown to the South Australia/New South Wales border; a new 275–330kV substation at Bundey; additional substation and line works to connect into the existing transmission network; and a new Special Protection Scheme and associated studies, commissioning and testing.

The progress The project’s first transmission pole was installed at the Robertstown substation, about 130km north of Adelaide, in February 2022. Stage 1 of the project will be complete by the end of 2023. ElectraNet developed a project-specific commercial strategy and framework to ensure it provided the best outcomes for the project and power customers. The strategy featured extensive industry engagement, incorporating both domestic and international contractors considered experienced and capable of performing the scope of works required. The strategy and engagement have resulted in: » An optimised concept design and delivery methodology » Efficient project delivery as designs evolved from initial concepts to detailed design


ElectraNet is delivering the South Australian component of Project EnergyConnect, which includes a new 200km double circuit line, additional substations, and a new Special Protection Scheme.

» »

Improved risk allocation and management, with project risks residing with the party best able to efficiently manage them An efficient project schedule optimised to ensure the best project outcomes

The objective The objective of Project EnergyConnect is to improve the affordability, reliability and sustainability of electricity supply in the National Electricity Market (NEM) through increased electricity transmission between South Australia, New South Wales and Victoria. The aim is to create a net benefit to consumers and producers of electricity, and support the transition of the energy market to a lower carbon economy using the following means: » Enhancing security of electricity supply in South Australia by providing a second major interconnector to the rest of the NEM » Increasing electricity supply competition and trade by improving network access and capacity, thereby reducing wholesale electricity costs using market means » Providing new opportunities for renewable energy and other energy projects to connect to the NEM, thereby stimulating economic activity and facilitating transition to a low carbon economy It is expected that the achievement of these objectives will provide a wide range of benefits at a local, state and national level. The challenges As with any project of this size, there have been several key challenges so far, with the task of selecting the most appropriate contractor a majority priority. It was predicted that the energy system in Australia was going to transition over the next 10–15 years, placing considerable demand on key skills, labour and material supplies. Labour and skill shortages were predicted to become a significant factor for transmission infrastructure with shortages and constraints predicted for line workers, electricians, construction managers, electrical and civil engineers. It was also expected to significantly increase consumption of steel and concrete. The project found itself in a market with significant competition for these resources.

ElectraNet developed a commercial strategy and framework for the specific purpose of delivering the project while ensuring best for project, best for customer outcomes. The strategy has facilitated extensive industry engagement, incorporating both domestic and international contractors considered experienced and capable of performing the required scope of works. The next key challenge will arise once the assets are built and connected between the states. The final phase of the project will be the integration of the interconnector into the NEM. This will provide significant challenges with system integration activities including the preparation and implementation of a test plan to allow the transfer of capacity to be safely and reliably increased between the states up to its maximum.

The maintenance The design life of the new transmission line, with appropriate maintenance, is approximately 100 years and during standard operation, the transmission line will require minimal ongoing maintenance. Inspection and maintenance activities are predominantly carried out by light 4WD vehicles. The maintenance program typically involves ground inspections every three years for signs of unusual wear, structural integrity and corrosion or damage. Helicopterbased inspections are undertaken annually. The future New interconnector projects like Project EnergyConnect play a critical role in supporting the transition to a low carbon economy. Many of Australia’s networks are aging and require important and required investment to facilitate this transition. In South Australia, transmission network costs are about ten per cent of a ‘typical’ residential customer power bill. The state has one of the oldest transmission networks in the country and timely investment in new transmission infrastructure is needed in order to transition to a renewable energy grid. Infrastructure investment in projects such as this will enable the power generated in renewable energy zones, which are normally located in remote parts of Australia, to be transmitted to cities and towns. It will also enable households to connect more solar, batteries and electric vehicles to the grid.

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Q&A: WESTERN VICTORIA TRANSMISSION NETWORK PROJECT With its abundance of wind resources, Victoria holds natural advantages that could make it a leader in the renewables arms race. However, it is widely acknowledged that more transmission will be key to unlocking the transition to renewables. One such initiative is the Western Victoria Transmission Network Project (WVTNP), a proposed new 190km overhead high-voltage electricity transmission line managed by AusNet that will carry renewable energy from Bulgana in the state’s west to Sydenham in Melbourne’s north-west. Energy magazine spoke to the Executive Project Director, Stephanie McGregor, about the opportunities and challenges around the project, and what’s being done to earn social license with local communities.

Energy: What are the expected positive outcomes from the installation of the Western Victoria Transmission Network Project’s 190km transmission line for consumers and for the state’s energy network? Stephanie McGregor: The project is critical infrastructure that will unlock the renewable energy potential of Western Victoria as a key Renewable Energy Zone and will help to deliver clean and affordable energy to Victorians. This includes the potential to unlock up to 900MW of renewable capacity, enough to power more than 500,000 homes. As well as this potential, it is needed to urgently reduce congestion as the existing transmission network in Western Victoria is at capacity. This means only limited power can be transported out of the region into the wider network. This project is one of many proposed for the state, to help harness green energy from a number of identified renewable energy zones in Victoria, as we move away from coal-generated electricity over the coming years.


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E: What steps are being taken to ensure the best possible outcomes for the project and the community? SM: The location of the proposed route has been selected to follow existing transmission line easements where possible, and minimise impacts including on houses, Aboriginal cultural heritage, agriculture, and native vegetation. Input from the community, stakeholders and landholders has been critical and will continue to inform design as we prepare the Environment Effects Statement (EES) for this project. During 2021, we held 15 in-person information sessions, ten webinars and 40 one-on-one online meetings – and this engagement is ongoing. We also have a team dedicated to liaising directly with landholders along the route. We are incredibly aware that for all the significant benefits of a major project of this size, there will be landholders along and near the transmission route for whom the project is challenging and stressful. We understand that and we will continue to consult, seek feedback, and listen to their concerns.


L: Transmission will be key to expanding renewable energy in areas like Victoria, where wind resources are abundant.

E: What is AusNet Services’ response to those who want underground construction of the transmission line? SM: There is still further work to do as part of the EES for the project, but we know undergrounding is an important issue and that’s why we shared a summary of preliminary investigation findings with landholders and the community late last year. These findings suggest that overhead construction results in less ground disturbance, provides more cost-effective connections for renewable energy generators, achieves electricity system availability requirements, and is a proven solution over the distance and capacity required for this project. Further technical information, including further cost and design information, will be provided as part of the EES which will be exhibited for public comment. E: Are there any sections of the route which are being considered for undergrounding? Which areas are they? SM: We’re continuing to investigate a range of options to reduce impacts along the route as part of the EES, including sections of underground construction and different designs and structures. This includes investigating undergrounding in some sections in areas where there are many types of impacts that could be mitigated by undergrounding subject to further assessment. E: What are the challenges the project faces at Hepburn Lagoon, Darley and Melton Aerodrome? SM: We’re continuing to consider alternatives at Hepburn Lagoon, Darley and Melton Aerodrome to assess how impacts on matters such as visual, landscape, ecological, Aboriginal cultural heritage, land use and aviation impacts between alternatives compare. This includes undertaking further technical assessment and community and stakeholder consultation. This is a complex project, and it is important to take the time to investigate these alternatives to minimise impacts as far as possible.

E: What considerations has AusNet Services taken in selecting the proposed route with reference to residential homes? SM: We’ve listened to feedback from landholders and communities about avoiding heavily populated areas and houses and have taken this into account as far as practicable. The location of the proposed route has been selected to maximise the distance from houses and to follow existing transmission line easements where possible. E: Are there any other comments you would like to add? SM: This project will help unlock the vast reserves of green energy in Western Victoria and open up the opportunity for even more renewable investment, such as solar and wind farms. We fully understand the stress and uncertainty a project of this size can create for local communities, notwithstanding the important benefits it has for the entire state in terms of bringing renewable energy to the grid. We will continue to consult with landholders and communities, seek their feedback, and listen to their concerns.

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WHEN DISASTER STRUCK: ELECTRICITY DISTRIBUTOR LESSONS FROM THE NSW FLOODS The 2022 flood events across the North Coast of New South Wales broke the record books. Labelled a ‘one–in-1,000-year’ event, unprecedented amounts of rain caused major flooding and widespread devastation, leading to much of northern New South Wales and southern Queensland being declared Natural Disaster Zones. Essential Energy, the state-owned electricity infrastructure company for New South Wales, has been front-and-centre throughout the disaster, sharing some unique insights on restoring and maintaining power and, importantly, keeping workers and the community safe.


ragically, lives were lost, and thousands of houses and businesses were significantly damaged or destroyed. Essential Energy’s Lismore and Murwillumbah depots were flooded, with the Lismore depot completely submerged. Electrical infrastructure across many towns in the Northern Rivers was also submerged, including the Lismore South Zone Substation and Lismore CBD. Essential Energy said that a number of local employees lost homes or experienced significant damage to their or loved ones’ property, and as the business supported these people, their eagerness to assist with its response was a testament to the strong and resilient community across the area. The flooding impacted customers from Tweed Heads in the north through to Coffs Harbour in the south. Essential Energy enacted its emergency response plan and prepared for a safe, steady and sustainable response.


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The early days As communities dealt with the muddy aftermath of extraordinary rainfall, and floodwaters continued to move downstream, impacting more communities, Essential Energy utilised helicopters to get a bird’s eye view of the damage to the electricity network. Damage was widespread with trees over powerlines, significant landslips, poles washed away, and electrical assets completely immersed in water. Essential Energy Head of Operations, Brendon Neyland, said the immediate focus was on making the network safe, assessing damage, mobilising team members and making repairs to the electrical infrastructure where it was safe to do so. “The safety of our teams and customers was our priority. This included de-energising the network as water levels increased while warning customers to remain vigilant when boating in floodwaters, and not enter properties that had been affected by floodwaters without knowing the power was disconnected,” Mr Neyland said.


“There was also a strong focus on solar panel safety and the need to take additional care due to systems being able to generate an electrical current regardless of whether the power is on or not.” Understanding many customers were without internet for extended periods, Essential Energy placed electronic road signboards around the community with specific information to assist customers. It also developed hard copy fact sheets and hand-distributed them throughout the flood recovery area – to evacuation centers, and recovery hubs. The fact sheets covered a range of information, from safe generator use to cleaning up with excavators and bobcats, Look Up and Live, to staying away from fallen powerlines. Safety was key and as part of the response, Essential Energy disconnected 7,000 water inundated properties from the network. “When a property is inundated by water, it needs to be checked for safety by an electrician before it can be reconnected,” Mr Neyland said.

“Our team developed a simple three-step process to assist customers with getting their power back on. As of last month over 4,600 properties had completed the check and been reconnected.” Teams from across the state mobilised to start clearing significant debris, trees, and even in one case, a washing machine, from Essential Energy’s assets. The company’s whole-of-business response included 210 local employees and 215 travelling crew members from 30 locations across New South Wales. It’s standard procedure for Essential Energy to conduct digital Hazard Identification Risk Assessment Controls (HIRACS) before commencing operational work, which were needed in bulk in this case. “2,215 HIRACs were completed during the response and teams were supported on the ground by our safety business partners who also played a key role in ensuring the community was kept well-informed of risks,” Mr Neyland said.

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SAFETY AND RISK MANAGEMENT four days of the water receding, ensuring power for many rural customers and key areas of Lismore,” Mr Neyland said. The Lismore CBD was a key focus area for Essential Energy, with the entire underground network underwater for days. “Every asset needed to be checked, tested, repaired or replaced. This also had to be repeated across the overhead network, which is unique in the Lismore CBD as it is positioned under building awnings and required specialist teams to undertake the work,” Mr Neyland said. More than 50 padmount, chamber stations, switching units and cabinets were tested, repaired, or replaced along with 98 underawning main boxes and cubicles. 348 fleet vehicles were used over the response and more than 50,000L of fuel was consumed. Despite the devastation and heartache for many, Essential Energy said community and local volunteer organisations were instrumental in their support by providing storage for electrical equipment for repairs, accommodation, and food provisions for the team on the ground. “One incredible act of community spirit saw residents of Upper Wilsons Creek digging a hole for a new pole themselves, which was delivered by helicopter alongside crews to allow repairs to be made,” Mr Neyland said.

The road to recovery Essential Energy logistic and fleet teams delivered supplies into the area including food and water for its teams, new poles, crossarms, cable, fuel, and specialised fleet equipment, boosting local supplies as access became available. Access remained a key risk throughout the response, with landslips, boggy ground, roads, and bridges washed away. Crews used drones, helicopters, and specialised fleet equipment to access parts of the network, however, this was a slow process. Helicopters and excavators were also used to restring powerlines and were instrumental in getting the power restored for many rural customers. The South Lismore Zone Substation suffered significant damage due to complete water inundation. Temporary repairs were made to get the power back on, with temporary switchboards arriving by semi-trailer. It will take over 12 months to completely repair the zone substation with permanent works to ensure a robust and long-term power supply. The Lismore Uni Switching Station was also partially submerged, damaging secondary systems in the control room on site. “With support from Engineering and System Control, teams worked to bypass the secondary systems to restore supply to both the Lismore Uni and East Lismore Zone Substations within


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Flooded for a second time “As our teams made repairs and power was slowly being restored across impacted areas, the community was flooded for a second time,” Mr Neyland said. “This flood, although not as high as the initial flood, still broke previous records and again devastated the area, with clean up and repairs needing to start over for many. “Despite this set back, our work continued and power restoration maintained momentum as we worked through the challenges while keeping our communities and teams safe.” In total, 69,603 individual customers were affected by a power outage during the two events. An empowered future With over seven weeks of a safe, steady and sustainable response, Essential Energy said the electricity network was fully available for customers to reconnect just before the Easter Long weekend. While there will still be work to be done at its Zone Substation sites across Lismore, Essential Energy said it would continue to provide significant support as customers were rebuilding and reconnecting to the network. Essential Energy has now turned its attention to lessons learned and adaptive planning to build a more resilient network to withstand the increase of network events on its assets, while ensuring a safe and reliable supply for its 880,000 plus customers across regional and rural New South Wales and southern parts of Queensland. ”I want to personally thank our customers and the organisations across the flood-impacted areas of northern New South Wales for their ongoing patience, support and assistance on the ground,” Mr Neyland said.


REMOTE MANAGEMENT KEY TO POWERLINE SAFETY Downed powerlines are a major industry safety issue. Downed conductors and their subsequent touch and step potential field affect a large radius, and current industry-standard technology is not always capable of alerting the control room when the line is down and connected to the load side – until now.


he safety issue of detecting and locating High Impedance Faults (HIFs) is a consistent industry problem due to the difficulty in detecting the small magnitudes of fault current. HIFs become more dangerous when the lines fall onto roads and unaware civilians may touch and sustain significant injuries. Even standing near fallen lines can be fatal due to the step potential points maintaining dangerous levels of electric current radiating outwards from the powerline. Currently, HIFs remain a significant hazard until found and reported. They are also costly both financially and reputationally. In an Australian first, PowerPilot has been created with these safety and hazard concerns in mind. Created by Electronet Technologies in New Zealand, PowerPilot is a small, self-contained device that attaches to the load side of the transformer, and can include Class 1 metering, identifying a range of fault conditions of lines and helping to prioritise responses.

PowerPilot’s ConductorDown fault sensing can detect if a live HV conductor is down when it falls to the ground while still connected at the load side. With PowerPilot, companies can measure the voltages and phase angles of threephase transformers and reliably detect an open circuit on one of the upstream high voltage conductors. For instance, a load-side conductor could be down where there is insufficient earth fault current to operate a protective device. The probable location of the fault can be inferred by PowerPilot with faults grouped together to assist in their detection and prioritisation. The “Last Gasp” loss-of-power report informs a control room immediately of a fault. This can mean a crew responds to hazardous situations such as a “conductor down” faster and reduces the time anyone is exposed to danger. Additionally, whenever power is lost, PowerPilot uses a small amount of stored energy to report the outage meaning maintenance crews can be dispatched sooner.

PowerPilot’s new technology allows for near real time data on LV network performance and power flows, reliable and cost-effective but low capacity two-way communication systems, and the ability to manage load at multiple levels such as Feeder and Zone Sub. The new industry technology has a plethora of additional services and uses available. For more information, go to:

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The uptake in the development of fuel cell electric vehicles has been followed by a rise in the setup of infrastructure for hydrogen refuelling around the world. The need for fast, accurate and safe refuelling requires sensors suitable for hydrogen applications.


he Federal Government has identified hydrogenfuelled vehicles as a key component of its Future Fuels and Vehicles Strategy in line with its technology-led approach to reducing emissions in the transport sector. As more federal and state funding is announced for hydrogen fuel service stations, and demand subsequently increases, so too will the need for suitable and certified technology to cater for the market. HYDAC’s pressure transmitter series HDA 4400 and HDA 4100 are geared for this market.

HYDAC’s pressure transmitter series HDA 4100

“The HDA 4100 is an absolute pressure transmitter, and because there are only three to ten bar extra pressure measurements needed in fuel cells on test benches, we can provide this product to the market,” a HYDAC spokesperson said. The HDA 4400 has a pressure measurement cell with a thin-film strain gauge on a stainless-steel membrane. The output signals 4-20mA or 0-10V enable connection to all HYDAC Electronic GMBH


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measurement and control devices as well as standard evaluation systems such as programmable logic controllers (PLCs).

HYDAC’s pressure transmitter series HDA 4400

The spokesperson said that the transmitter has been ATEX, IECEx and North American certified, among other certifications. The spokesperson added that HYDAC also offers redundant pressure transmitters where the sensor cells are welded side by side. “Inside the housing, we find two galvanic isolated electronics and the transmitter has two output signals. This is called a category three system architecture, which is also ATEX and IECEx certified because there are more and more functions in the refuelling stations that need to be CO2 certified,” the spokesperson said.

Two benefits in one “If a customer chooses two pressure transmitters, which they install in an identical circuit, then all signals are read in the PLC, and a cross-monitoring of both signals takes place in the PLC. The same thing can be done with a

redundant return pressure transmitter,” the spokesperson said. “During this cross-monitoring, the customer saves one additional process connection.” The spokesperson said the ‘categoryto-architecture’ pressure transmitter was developed to accommodate the growing demand for CO2 functions in the energy industry. “This pressure transmitter does have one sensor element, a very specific electronic with various functions or various parameters,” the spokesperson said. “In the case of an error being detected inside the transmitter, the signal is pulled down to three million, which is a signal for the PLC to print the system to ‘safe’ state.”

What is the difference between a hydraulic pressure transmitter and a hydrogen pressure transmitter? “The answer is that HYDAC specifically designed the hydrogen pressure sensor for the hydrogen market,” the spokesperson said. “This means we designed a sensor cell and a process connection made from special stainless steel; it's 144/35 with a minimum nickel content of 13 percent. "The mechanical connections are designed to limit wetted surfaces and to provide perfect sealing for hydrogen gas. “This material is ideal against hydrogen corrosion – embrittlement caused by hydrogen low temperatures that cause fractures in standard stainless steel.” For further information visit:

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by Andrew Richards, Chief Executive Officer, Energy Users Association of Australia

With the supercharged push towards net zero targets, energy markets are becoming extremely complex. As the Australian energy landscape changes at such a rapid pace, energy users can no longer afford to be passive observers.


he Energy Users Association of Australia (EUAA) is the peak body representing Australian industrial and commercial energy users. Its membership covers a broad cross-section of the Australian economy including significant retail, manufacturing and materials processing industries. Combined members employ over one million Australians, pay annual energy bills in the many billions of dollars and support the development of a lasting national energy and climate change plan that puts downward pressure on electricity and gas costs. The EUAA supports the pursuit of net zero targets and has been helping member businesses act to reduce emissions for some time. In fact, over the last five years, businesses have been large drivers of new renewable projects, underwriting them with long-term offtake agreements. But while renewable energy is one of the easier actions a business can take to address their overall emissions profile,


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there are many other issues that need to be addressed and it is often these areas that require deep thought and are more challenging to address. Recent reports of escalating electricity and gas costs provide concrete evidence of what many consumers have feared for some time; that energy markets will be highly volatile as we navigate our way to net zero. Not unexpectedly, a hard-fought federal election is adding to the complexity of the debate. Regardless of who wins the federal election or who the next Energy Minister will be, energy users are looking for a post-election re-set that sets a clear path to achieving net zero at least cost, not at any cost. While the debate over how we get to net zero continues to be highly contentious, if energy users are to successfully navigate the energy transition, an impartial assessment of the challenges and opportunities is required, as only then can we design policy that is truly consumer-centric.

We often see a narrative that achieving net zero will be easy and cheap, when the lived experience for many commercial and industrial energy users is that it is hard and potentially very expensive. That is not to say we shouldn’t do it, but that we need to have our eyes open to the challenges. The EUAA seeks to support our members in taking positive action to reduce their emission footprint – such as entering into long-term renewable energy power purchase agreements (PPAs), enhancing energy efficiency, and taking initial steps to re-shape their manufacturing processes to accommodate future low emissions technologies if and when they become commercially viable.


CHALLENGES WARDS NET ZERO At a broad policy level, we see that the existing Federal Emissions Safeguard Mechanism could be a useful way to gradually lower emissions but also that it will require careful modification and a range of supporting policies that recognises not all industry sectors can move to net zero at the same pace. Helping those in hard-to-abate sectors will require careful planning and tailored responses from government that includes targeted R&D and technology deployment funding as well as assistance for tradeexposed, energy-intensive industry. It is also important to recognise that not all industrial processes can be decarbonised or that it may take many years for zero emissions technology to become commercially viable. So access to a broad range of highly credible and verifiable offsets will be vital. The transition away from methane gas to either green gas or full electrification is just one example. Rewiring the national electricity market is also a significant challenge. While more electricity transmission assets will no doubt be required, the sheer scale and timelines being spoken about are unprecedented. We need to recognise this has never been done before. As it stands today, energy users will wear all the costs and bear a majority of the risk of these assets and it will likely lead to a sharp increase in energy bills.

The scale and cost of the challenge can’t be underestimated with an excess of $40 billion in new transmission anticipated over the next decade alone. Therefore, the response from governments needs to be scaled to match the challenge. For example, well-targeted funding to support identified critical infrastructure can play a role in moderating the costs and risks energy users face. And using this funding to leverage private investment only where a clear need has been identified will be critical as will seeking some level of co-funding from connecting generators. Calls to weaken the role of the Australian Energy Regulator or require less than a robust economic assessment of transmission infrastructure are a recipe for disaster for energy user bills. While open to improving regulatory processes, the EUAA will not support a dilution of good governance and robust economic analysis of infrastructure that consumers will be expected to pay for over the coming decades. Finally, the continued use of gas will likely be required for some time to ensure that long-duration gaps in energy supply are sufficiently managed and as a critical input as both heat and product for many industrial and manufacturing processes. However, with global energy markets undergoing significant upheaval, unaffordable gas prices loom large in the

minds of energy users. The continuation of federal policy that monitors domestic gas availability, the enforcement of the Gas Industry Code of Conduct and an ongoing monitoring role for the Australian Competition and Consumer Commission (ACCC) will provide critical protections for all domestic energy users. At the same time, we need to look at all the alternatives to traditional methane. Hydrogen could play a role but it has a long way to go to be cost-competitive while the cost of converting consumer side equipment, which will amount to many billions of dollars, seems to be dramatically underestimated by many. The pursuit of biomethane should not be abandoned as it has the dual advantage of having significantly lower emissions than traditional methane and does not require expensive re-tooling of the network or customer facilities. For decades, the challenge and opportunity of finding a new way forward to reduce our emissions has been in the news and has been talked about in the community. But, as the saying goes, “the devil is in the detail” and, sadly, many domestic energy users seem to be unaware of the potential price hikes and impacts heading their way.

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HOW ENERGY WORKERS CAN PROTECT THEIR KIDS’ HEALTH FOR LONGER The Federal Government recently changed legislation to allow private health insurers to cover young people who are dependent on their parents for longer. While this change is not compulsory, rt health – the specialist provider of health insurance for energy and transport workers – is committed to ensuring the best deal for its members and their families.


ustralia’s first registered private health fund, rt health, recently announced it is helping families to keep their kids covered for longer by offering cover for dependants up to the age of 31.

The not-for-profit fund, now a division of HCF following the merger, announced the age limit extension for eligible older dependants covered on family memberships to help make healthcare services more affordable and accessible for young people. rt health said, “We know healthy families are happy families – no matter how old your kids are.” “When your kids are young, it’s easy to keep them protected. But as they get older and more independent, it’s good to know you can still protect their health. “As a not-for-profit private health insurer, we’re always looking out for ways to help our members. So, what better way than helping you cover your kids into adulthood.”

Keeping your kids protected rt health said that families change over time, and with many young adults pursuing higher education and living in their parents’ homes for longer, this is a great way to help protect their health until they turn 31.


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Who can be covered? Children who are full-time students can be covered under your policy for no additional charge. If you have kids who are not studying full-time, they can be covered under a Family Extension policy. There’s a small additional premium (but much less than the amount they’d pay for both their equivalent single person cover). This means a big saving for young people and peace of mind for parents. About rt health rt health was the first registered health fund in Australia, founded by railway workers in 1889, and is the not-for-profit, specialist health insurance provider for transport and energy workers. rt health knows what working in the energy industry is all about and can advise on the best cover to suit your lifestyle and your health concerns. rt health looks after the Australians who keep Australia moving. For more information, head to the rt website: under ‘Your cover: Kids covered to 31’

Guess who rt health is for? rt health is an industry health fund that started more than 130 years ago. Our vision is to support rail, transport and energy workers so you never have to worry about managing your health concerns alone. Energy workers, we’ve got you covered.

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AUSTRALIAN INFRASTRUCTUR The Transgrid Victoria-NSW Interconnector (VNI) upgrade project will help lower the cost of wholesale electricity across the National Electricity Market and enable better power flows between Victoria and New South Wales by unlocking 190MW of additional energy, enough for 30,000 homes. Transgrid will do this, without the need to build additional transmission line infrastructure, by installing clever technology at their substations at Stockdill in the ACT and at Yass in New South Wales.


or the construction phase of the VNI project, Transgrid contracted Zinfra, a leading national engineering, construction and maintenance service provider. A well-established and trusted partner to industry, Zinfra is using its expertise and a committed team for the installation of innovative SmartValves technology from Smart Wires at the substations.

First large scale installation of SmartValve technology in Australia The SmartValve technology pulls energy off of congested lines and pushes it onto lines with spare capacity. It will stabilise the grid, reduce congestion and will also enable power from renewable resources to flow from where it’s generated to where it’s most needed. Zinfra has successfully installed nine SmartValve technology units at the Stockdill

The completed Transgrid Victoria-NSW Interconnector (VNI) upgrade project at Stockdill, ACT.


substation and is currently preparing for a further six units to be installed at Yass. Each unit weighs in at just over eight tonnes and sits on 6m-high support structures. A corona cage, a steel cage which wraps around each unit, was erected, topping the installation out at almost 10m. Once the SmartValve technology units are commissioned, they will be the first installed in Australia of this model at this voltage.



RE ELECTRICITY PROJECT Flexible approach to challenges Zinfra’s internal electrical crew successfully delivered the installation at Stockdill safely while managing challenges including restricted daily outages and dealing with new equipment. The experienced and committed Zinfra team continued to deliver, despite the challenges of a COVID-19 lockdown between New South Wales and the ACT, which saw the crew spend between three to five months on site. “Transgrid and Zinfra worked together, despite the many challenges, to support our crew, who went above and beyond for project delivery at Stockdill,” Zinfra Lead Project Engineer, Victor Sayaxang, said.

“Despite the challenges, the Stockdill project was completed before schedule and informs our work at Yass. This has enhanced Zinfra’s reputation as a delivery partner that can be relied upon to deliver non-standard, complex solutions in challenging circumstances.”

Making safety the number one priority Zinfra continues to ensure that safety remains the number one priority as works continue on the installation of SmartValves technology at the Yass substation. “Zinfra has competent resources on the project that provides safety and operational support,” Mr Sayaxang said.

Zinfra and Transgrid worked rigorously together to ensure that the best health and safety systems are in place, with regular communications between the Zinfra team and the workers on site to ensure compliance. HSE inspections were conducted daily, with findings communicated to the crews and learning outcomes put into action. “Our approach is that everyone takes responsibility for their own safety and the safety of others. That’s a big part of the positive safety culture that we've instilled on this project and other projects that we've been working on, whereby everyones’ safety is our individual responsibility,” he said.



VEGETATION MANAGEMENT THAT’S AHEAD OF THE PACK Meeting strict and increasingly complex regulatory requirements is perhaps one of the greatest challenges faced by most modern utilities. The inherently high-risk nature of the sector means it is highly regulated across a number of facets, with vegetation management being an area requiring particular attention. Meeting the challenge of adhering to vegetation regulatory requirements is too complex a task to be left to manual processes; which is where work management software comes in to simplify the process.


nergy network operators spend many millions of dollars managing vegetation proximity to powerlines annually, in order to mitigate the risks of service disruptions and serious hazards like bushfires, and maintain mandated clearances. Given the potentially catastrophic effects that can be seen when vegetation adjacent to powerlines is left unchecked, it’s clear to see why the industry has developed such strict regulatory standards when it comes to managing vegetation. And while incredibly important, the task for utilities to meet these regulatory requirements can be quite challenging. This is where work management software (WMS) comes in. WMS provides utility businesses with tools to effectively and efficiently track and manage their compliance-related activities. It also streamlines reporting, ensuring the required records are on-hand when the regulator comes knocking. Ensure you’re ready for the regulator Vegetation management regulatory frameworks and operating standards vary considerably between states and across energy networks. The appropriate clearance distance to prevent interaction varies depending on a range of criteria. These include: » The voltage of the powerline » The location of the powerline (whether it is in a bushfire risk area etc.) » The type of conductor (fully insulated, covered or bare) » Span length (longer spans will sag and swing more under hot/ windy conditions)


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Vegetation management is also impacted by differences in climate, geography and vegetation growth characteristics. Over decades, various regulatory frameworks and standards regarding vegetation management have developed in the different Australian states and territories. Even for networks under the jurisdiction of the national electricity market (NEM), there remain variations in regulation and standards. Within the NEM, the Australian Energy Regulator (AER) provides economic regulation, deciding on the revenue allowable for network service providers. These allowances are intended to be sufficient for an efficient Network Service Provider (NSP) to maintain their network in a safe, reliable and affordable manner, consistent with technical compliance obligations determined by state technical regulators. The vegetation management technical compliance requirements themselves are set and regulated by respective state governments through technical regulators or government departments. Differences between regulations in each jurisdiction originate from prior decisions by these bodies, which may have been driven by countless different factors over the years. In addition to regulations directly specifying vegetation clearances, a range of state and commonwealth legislation can indirectly affect vegetation management program design, management and cost in different jurisdictions. These may pertain to considerations such as environmental protection, protection of threatened native species or Aboriginal cultural heritage, biosecurity, heritage significance, chemical handling, and/or road use and safety. The penalties imposed by regulators for any

compliance failures also vary based on a multitude of factors.

Keeping it all in check with work management software Vegetation management is a task too complex to be left to manual processes. To ensure energy network utilities meet their regulatory requirements, an automated, digitised solution is a must; and Xugo is a cloud-based work management solution that is recognised as being best-of-breed when it comes to vegetation management. Xugo connects teams and processes, enables work programs, ensures processes run smoothly, and strengthens compliance with regulations, policies and standards across a business. Xugo provides the data accessibility and visibility needed for effective compliance control and enterprise risk management. With Xugo, users can manage all of the works associated with vegetation management, including creating and assigning tasks for planning, scoping, auditing and cutting. Users can schedule and track various activities in progress; as well as review audit results and other critical operational progress information via scheduled and dashboard reporting. Out in the field, contractors and service providers can track all of the work they undertake remotely by connecting to Xugo via mobile devices. In addition, crews can utilise the Xugo app, which offers significant offline capability in locations where network connectivity is challenging. It’s a rich experience that tailors to the prevailing conditions; wherever your crews may be. “Xugo provides utilities with the confidence to manage all aspects of their


vegetation management program,” said Matthew Croft, General Manager of SFI Allegro, developer of the Xugo software. “Services that can be undertaken with Xugo include annual planning, coordination of LiDAR collection and analysis, field service activities, reporting and contractor payments to help minimise fire risk, improving network reliability and enabling compliance management with current regulations. “Xugo functions as the authoritative data source and tracks and allocates work to

provide transparency on the status across every vegetation network span. “Importantly, Xugo can also be easily interfaced with corporate systems, for asset, network and financial information.” By managing your compliance-driven data, Xugo powers your compliance framework and increases visibility of your safety, quality, regulatory and enforcement programs. Xugo streamlines compliance activities, including carrying out inspections, safety checks, audits and incident investigations (including those

from customers), as well as the processes involved in compiling reports for regulators. Compliance can be tracked in real-time to drive continuous improvements. The team at Xugo can configure the software to your business needs, allowing flexibility and full integration with your current operations, procedures and policies. Additionally, this adaptability ensures that Xugo can evolve in response to any enterprise changes. The solution is also scalable, ready to grow with your business.

For more information on how Xugo can help your business manage its vegetation compliance activity, head to:

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MARK THE FUTURE OF ELECTRICITY NETWORKS As electricity networks look to transform, grow and adapt to the ever-changing energy landscape, one of the biggest challenges is planning for an uncertain future. Energy Queensland’s solution was the development of a sophisticated automation system – one that maintains efficiency, safety, and cost-effectiveness. Energy magazine spoke to Dr Andrew Thomas, Principal Engineer Strategic Planning, Energy Queensland, about the company’s new technology and what it means for their electricity networks.


nergy Queensland, which is 100 per cent owned by the state of Queensland, comprises of electricity distribution, retail and energy services. Its electricity network businesses, Energex and Ergon Energy, manage a large area, meaning efficiency and accuracy are crucial. Dr Thomas said the goal of automated system work is two-fold: to enable the networks to autonomously make accurate strategic planning decisions over the thousands of constraints that the automated network modelling can produce, and to build a system that can aid planners in breaking down the complexity in building the future network. “Given the multitude of new factors which increase planning complexity – various photovoltaic (PV), electric vehicle (EV) and battery uptake scenarios, more dynamic control devices, dynamic operating envelopes, aggregator/retailer interventions in the distribution network – it is hoped that an artificial intelligence (AI) system can learn to make least-regret decisions in such an environment,” Dr Thomas said. Developing a forecasting system “The automation system that we have developed has a number of distinct components,” Dr Thomas said. “The first is a new load forecasting system, developed by the Energy Queensland Strategic Forecasting team. It is based on standardised load profiles for normal residential and business customers, but also for new technologies such as PV systems, EVs and batteries. “The forecasting team is involved with creating various uptake and technology use scenarios (e.g. various EV charging profiles), and these flow through to new load forecasts at various levels of


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the system – for instance, at our Bulk Supply Points (e.g. 132/66kV substations), our Zone Substations (e.g. 66/11kV substations) and distribution feeders (e.g. 11kV distribution network). “This system generates maximum and minimum demand forecasts, to understand both peak load impacts on the network and also minimum demand/reverse power flow impacts.”

Programming and planning For the next step of the automation system, Energy Queensland uses two key types of software: Python and PowerFactory. Python, a high-level programming language, allows for the effective integration of other systems. PowerFactory, on the other hand, is a “ leading power system analysis software application for use in analysing generation, transmission, distribution and industrial systems”. Once the forecasts have been generated, they are then applied through Python programming language scripting to the PowerFactory models of the network. Automated load flows, through the PowerFactory-Python application programming interface (API), are then run utilising parallel processing over several virtual machines, under all the various modelled scenarios, maximum and minimum demand, out to 2040. “This process produces lots of data – normal and contingency capacity of all the various transformers, lines and cables in the network, and also voltage information,” Dr Thomas said. Following this, the next step is to apply the planning criteria to this information, again using automated analytics and scripts, to generate a forecast of expected constraints on the network under the various scenarios. “This information is useful on its own terms, but even more useful when converting this forecast of constraints into expected future capital expenditure,” Dr Thomas said.


“Literally thousands of future network constraints could be forecast from this system, far too many for manual analysis – so the challenge is to determine expected strategic expenditure arising from these constraints in an automated way.”

The current system vs a future system “The current version of the system uses a rule-based system to determine estimates of possible solutions to each constraint. For instance, if the voltage on a distribution feeder is projected to be outside of planning limits in 2030, we could assume that a new voltage regulator will solve this problem,” Dr Thomas said. “The final stage of this system is to extract relevant information, summarise findings, and produce visualisations to aid and inform the rest of the business in decision making and planning. “However, we are also working on a new system that uses machine learning/AI to determine the best solution in a more accurate way, using a machine-learning methodology called ‘reinforcement learning’. Early proof-of-concept work looks promising in this endeavour.” Automated planning in the transition to net zero When it comes to transition to net zero, Dr Thomas said automated planning has an important role to “enable us to make least-regret decisions”. As major network augmentation means developing assets with long usable lives (which now stretch well into and through energy transition timeframes), the risk of regret increases, meaning these investments need to be carefully considered with a view to the possible future scenarios.

“Automated planning allows us to quickly and efficiently explore many possible future scenarios and analyse their impact on the network and future network expenditure,” Dr Thomas said. “Armed with this information, we can produce better business cases that minimise regret in investment decisions now and into the future. “Using these tools that we are developing, we hope to be able to help Energy Queensland enable, manage, and optimise the transition to the new energy future for our customers.”

The future of AI in energy applications Dr Thomas said there are still many applications for AI in the energy sector that are yet to be discovered and applied. “In the strategic planning area, Energy Queensland has the view that AI can be used to train intelligent ‘agents’ that can make good planning decisions, which is what we have been trying to prove or demonstrate in the proof-of-concept work,” Dr Thomas said. “Using the reinforcement learning methodology, we are training an autonomous agent, whose ‘brain’ is a deep neural network, to interact with load forecasts and our PowerFactory network models to make good network augmentation decisions in order to lower the risk of constraints and also to minimise capital expenditure.” Dr Thomas said that AI systems may never supersede a human planner, but that their applications definitely have promising benefits for the industry. “It will be a long time – perhaps never – before an AI system can do the same, detailed planning work of a human planner, but it is hoped that this system will find possible new solutions or approaches, in the presence of network complexity, that improve the outcomes for planners, the network and customers.”

June 2022 ISSUE 18





In Western Australia, our network is different; we have one of the world’s largest islanded grids that spans 254,000m2 presenting unique, sometimes difficult, but always exciting challenges in ensuring the continued power supply to more than two million customers. How we manage the South West Interconnected System (SWIS), which includes both the transmission and distribution networks, is always evolving as we look to develop, trial and incorporate new technologies and delve deeper into our data.

ur path towards decarbonisation and enabling the rapid growth and integration of renewables into the network has seen us think outside the box – how can we enhance and improve customer energy solutions while ensuring equity for all. In planning for the changing energy landscape, which is being evidenced around the world, we’re transforming to a modular grid to ensure a cleaner, brighter and more resilient energy supply for the next generation. We want to ensure that we continue to meet the changing energy needs of Western Australians and this means looking at how we can better manage the network and deploy innovative customer solutions. We are aiming to ensure that Western Power can support greater energy needs being delivered by renewable resources by 2031. Already there is more than 1.6GW of solar photovoltaics (PV) connected to our distribution network – that’s one in three households and this is set to be one-in-two by 2030. How we’ve planned for a safe, decarbonised and reliable network of the future with the growth of renewables and changing climate has seen the birth of the Grid Transformation Engine (GTEng) – an innovative proof of concept scenario modelling tool that we’ve developed in-house. This ground-breaking modelling maps out what our network will look like in 10, 20, 30 plus years, enabling a new dimension in our decision making. GTEng uses intelligence from our data processing, electrical engineering, modelling and optimisation methods to form a cutting-edge planning tool that allows for multiple scenarios around future power needs and use. It processes complex and wide-ranging data to create visualisations and forecasts of different scenarios, including population and demographic predictions, economic forecasts, customer needs and profiles, energy generation and loads, energy use and location mapping.


It involves multiple stages of data processing with different filters applied at each stage, which help us visualise what the potential energy landscape will look like and what we need to maintain and improve power supply. As a Government Trading Enterprise (GTE) and critical service provider, the community is at the centre of everything we do. To that end, we built our customer profiles through engaging customer groups and understanding their current and future energy uses including looking at things like battery and solar PV uptake. We then took that information and spread it across our customer base to create different energy forecasting scenarios. When you combine the forecasts and customer demand profiles across the different scenarios, we get a unique view and clarity on the most efficient ways to service energy needs. It’s exciting in that we get to look at it from a clean sheet perspective – what would we do in an ideal state across those multiple scenarios? The results have been fantastic and extremely insightful, laying the foundation for a new way of thinking in how we better plan for the future. A key insight we’ve seen so far is the benefits of urban undergrounding power for our metro customer profiles while maintaining poles and wires for customers in the outer metro area. We also now know that a significant proportion of our distribution overhead network, more than 50 per cent, could be transformed into an autonomous grid using stand-alone power systems (SPS) and microgrids. With this new understanding, we’re now progressing from the network of today to the grid of tomorrow. This involves transition pathways and looking at our maintenance and renewal strategies and other inputs to be able to look at the most efficient economic pathway to transitioning the network. And this is where the GTEng comes into its own. Already we’re deploying SPS in regional locations where there are network and customer benefits. GTEng enables us to identify


distribution network feeders with different spurs that could evolve into an autonomous grid. It looks at the age, risk, and customer use of each spur and creates a net present cost view of using a traditional network solution versus an innovative solution such as an SPS. SPS provides our regional customers with a cost-effective, safe and reliable alternative to pole-and-wire power distribution, particularly in regional and remote locations where supply costs are high and power reliability and quality are impacted by distance, access issues, terrain and events such as storms and bushfires. Since rolling out our first pilot SPS in 2016, we now have 97 across the grid and we’re looking to deploy 1,000 in the next four years and 4,000 units in the coming decade. Modelling has shown that if we roll out 6,000 SPS, we'll be able to decommission more than 23,000kms of overhead assets. While SPS is a significant part of the transformation process, we’re aiming even higher, and looking to transform around 50 per cent of our distribution asset base. The GTEng also provides greater insights into the use and prevalence of distributed energy resources (DER) and the need for DER orchestration. The impact of solar PV penetration on parts of the network highlights the need for coordination to mitigate overload and the need for augmentation. Other scenarios we’re looking at include how an unmanaged EV charging situation, say at six o'clock in the evening, could impact the low voltage network and what augmentation would be required. This has helped inform our underground strategy in the metropolitan area. About 60 per cent of the Perth metropolitan area now has underground power with around 90,000 homes and businesses

converted from overhead to underground power since undergrounding began in 1996. Western Power has identified a further 300 projects across the metro area that will benefit from underground power in the next two decades. As a stand-alone grid, we collaborate more broadly with other energy utilities and agencies in Western Australia and due to GTEng’s scalability, we’ve been able to share forecasting scenarios for generation planning. This has provided us with a unique environment where we've got consistent information being used at the distribution, transmission and generation level, all of which are being driven by customer needs. We’ve basically created an ecosystem of modelling. We’re now looking at how we can expand our proof of concept for distribution into a transmission modelling tool, and then ultimately, more broadly integrate generation. This builds on the work we've done to successfully trial innovative solutions like SPS, battery storage and the Kalbarri microgrid. Along with improving DER integration, the coordination of advanced metering infrastructure (AMI) and modernised connection standards for DER we can successfully plan for greater amounts of grid-connected storage to help manage a mix of energy generation. The GTEng’s ecosystem of modelling helps inform whole-ofsystem planning for Western Australia by providing a consistent suite of information that's been able to give us a quality outcome across the board. It’s enabled us to trial and successfully progress transformational investment in existing assets and new technology on our path towards a modular grid ensuring better power outcomes for Western Australians.





AS CDR DEADLINE LOOMS by Luke Wines, Senior Manager Data and Analytics, EY With the recent release of the Consumer Data Right (CDR) rules for the energy sector, the Federal Government is lighting the fuse on energy retailers and their compliance with the CDR regime. With the go-live date fast approaching, retail electricity suppliers face a huge amount of work to do and little time in which to do it.




he CDR, the centrepiece of the Federal Government’s digital economy transformation, provides consumers across the economy with access to and use of the data that service providers hold about them, empowering them to make more informed choices and further promote competition in the digital age. The premise that consumers should be freely informed of their behaviour, as highlighted by their interactions with the likes of their bank or telco, is strongly supported by consumer advocates, and examples of data access, portability and security frameworks are proliferating around the globe, including in the UK, California and Brazil. Learnings from the banking sector The Australian banking sector was the first to contend with the introduction of the sweeping reforms to customer information management and will be closely followed by the energy and telco sectors over the coming three years. With the banking sector wading through rolling go-live dates over the past two years, cost and complexity are hot topics for the sector, with delivery programs requiring coordination of work across technology, risk, legal, customer and compliance domains.

Banks taking upwards of 18 months and allocating budgets in the tens of millions was the norm in delivering CDR-compliant systems and processes. On 1 July 2022, the first major go-live date for the nonmajor ADIs, nearly two-thirds of banks were non-compliant with the CDR, with this cohort immediately coming under scrutiny from the ACCC, the designated regulator of the CDR. For some, this attention has not abated as they have subsequently missed the following go-live date of the 1 November 2021, due primarily to a lack of access to technical resources and late or no delivery from key suppliers. None of this bodes well for the incoming energy sector with not enough groundwork done to date by electricity retailers to have confidence in achieving the high compliance bar set by CDR.

Difficult timing The introduction of the CDR comes at a tumultuous time for the energy sector, with overarching political considerations surrounding climate change and rapidly changing consumer preferences coinciding to create an environment of rising risk and uncertain returns. From the impairments being taken on traditional fossil fuel-fired assets, to the significant defection of customers from core electricity retail products and onto the emergence of major new competitors such as telcos, electricity retail is an incredibly complex business to be in.

Directors and management across the sector have their plates full with how they structure and operate their businesses in the face of such changes, with little apparent bandwidth left to pay attention to other concerns such as CDR. With a lack of consideration from senior leadership, implementation of the CDR is being left largely to technology teams, which, as an approach, misjudges the scope, complexity, and risk profile of, arguably, the largest element of the current regulatory reform agenda.

Early compliance is key Despite the complexity of the changing landscape in the energy sector, organisations need to shift their attention to accounting for CDR in the immediate future. Between the significant uplift required for technology solutions, the impacts on customer acquisition and retention, and the hefty penalties associated with a breach of the CDR, including potentially millions of dollars in fines and disqualification of corporate management, there is much to be considered by retailers, both large and small. There is still time to prepare and deliver well against the incoming CDR obligations, but with the starting gun having already been fired, that window is rapidly closing. Early compliance will be the most effective method of defence against the ever-vigilant regulator and the significant tools and powers they have at their disposal in their task of protecting and promoting the interests of consumers.




By Mikayla Bridge, Journalist, Energy magazine

Through the Australian Renewable Energy Agency (ARENA), Australia has partnered with the International Energy Agency (IEA) Bioenergy to develop solutions for seven Bioenergy Tasks. These tasks aim to ensure clean, viable energy for all countries involved, by replacing current fuel, gas, heat and power sources with cost-effective, renewable bioenergy.


EA Bioenergy, an international organisation set up in 1978, aims to improve cooperation and information exchange between 29 countries with national programs in bioenergy research, development and deployment. The organisation’s vision of ensuring reliable, affordable and clean energy to its state members is carried out through carefully structured tasks. These tasks each have set objectives, budgets and time frames. The majority of tasks outlined below set triennial goals, and are reviewed at the end of each three-year period. Bioenergy Australia participates in the following seven IEA Bioenergy Tasks. 1. Material and Energy valorisation of waste in a Circular Economy National Team Leader: Daniel Roberts, leader of the CSIRO Hydrogen Energy Future Science Platform This task aims to exchange information – between policy and decision-makers – on the integration of energy into solid waste management. The task also examines the changes presented by shifts towards increased recycling, resource recovery and zero waste initiatives. In recent task reports, Australia has demonstrated an impressive technical understanding of the key factors that must be addressed to prevent difficult-to-recycle waste from being landfilled. However, the increasing demands for nutrient and materials recovery from waste management systems places pressure on Australia’s existing technological pathways. Gaining a better understanding of the different pathways will be a significant focus for Australia moving forward. 2. Energy from Biogas National Team Leader: Bernadette McCabe, principal scientist at the University of Southern Queensland’s Centre for Agricultural Engineering This task looks at the biological treatment of the organic fraction of municipal solid waste, anaerobic digestion of biomass feedstocks, and the biogas production chain. Though the Australian biogas industry continues to evolve, Australia faces a number of challenges that are slowing down the development of biogas projects, such as financial viability of projects and a lack of widespread industry experience. Enea Consulting and Bioenergy Australia have recently provided recommendations for Australian governments to consider, such as setting renewable gas targets and introducing waste management strategies to support feedstock quality and quantity. 3. Commercialising Conventional and Advanced Liquid Biofuels from Biomass National Team Leader: Steve Rodgers, Business Development Manager at Licella, a globally leading company in next-generation advanced recycling


This task is focused on commercialising sustainable transportation biofuels. While there are numerous renewable energy options for heat and electricity generation, biofuels are currently the only means – both in Australia and globally – of displacing liquid fossil fuels such as gasoline, diesel and aviation fuels. Biofuels are not currently included in any Australian national renewables policy and whilst there is a federal biofuels incentive scheme, there is no federal biofuels policy. This is left to each state. To date, only Queensland and New South Wales have biofuels mandates. The current production of ethanol and biodiesel in Australia constitutes only about one per cent of the overall national consumption of petrol and diesel.

4. Biorefining in a future BioEconomy National Team Leader: Geoff Bell, Chief Executive Officer and Chairman of Microbiogen, the world’s leading developer of microbes for biofuel production This task analyses the concept of a bio-refinery, and explores and distributes information on biorefinery concepts and projects. This task also considers other products generated from biorefineries that are not considered by other tasks. These include: » Animal feed » Proteins » Biochemicals » Fibres As of May 2021, Australian Government policies are targeting a 26-28 per cent CO2 reduction by 2030. The Federal Government is developing a Bioenergy Roadmap through ARENA, which will help inform the next series of investment and policy decisions. According to the roadmap, ARENA’s investment priorities are: » Integrating renewables into the electricity system » Accelerating hydrogen » Supporting industry to reduce emissions

5. Biomass Feedstocks for Energy Markets National Team Leader: Mark Brown, Professor of Forestry Operations at the University of the Sunshine Coast, and a Director of the Forest Industries Research Centre and Australian Forest Operations Research Alliance (AFORA) This task seeks to promote bioenergy development that is driven by well-informed decisions in business and governments. This will be achieved by providing analyses, syntheses and conclusions on biomass feedstock to relevant individuals. In a 2021 task meeting report, the below topics were found to be of interest to Australian stakeholders: » Bio-hubs as keys to successful biomass supply integration » Dry matter losses during biomass storage » Novel regional and landscape based approaches to govern » Sustainability of bioenergy and biomaterials supply chains

WASTE TO ENERGY 6. Flexible Bioenergy and System Integration National Team Leader: Amy Philbrook, chemical engineer currently working in business development at ARENA This task contributes to the development and analysis of bioenergy solutions that can provide flexible resources for a low-carbon energy system. The objective is to improve understanding on the types, quality and status of flexible bioenergy. After a questionnaire distributed in December 2019 to Task 44 members, Australia was found to lag behind in terms of application of flexible bioenergy concepts. This is likely due to the low level of maturity of the bioenergy industry in the country. 7. Climate and Sustainability Effects of Bioenergy within the Broader Bioeconomy National Team Leader: Annette Cowie, the Principal Research Scientist, Climate in the New South Wales Department of Primary Industries This task aims to identify and address critical issues related to the climate and other sustainability effects of bioenergy and bio-based products and systems. This objective will be achieved by providing analyses that support well-informed decisions by land owners, communities, businesses and governments. Australia’s key goal is to increase national understanding of the environmental, social and economic impacts of producing and using biomass for bioenergy. The chief concern remains the development and application of science-based methodologies and tools for assessing the effects of bio-based systems. Work is currently underway in Australia to disseminate knowledge on successful mechanisms to improve the use of flexible bioenergy in different energy sectors. Bioenergy essential for Australia’s future As the world’s primary source of renewable power, bioenergy offers countries a sustainable replacement for current fuel, gas, heat and power sources that doubles as waste management. However, bioenergy technology is not yet widely deployed across Australia. Through Australia’s participation in the IEA Bioenergy Tasks, the country’s reliance on renewable energy is set to increase, consequently growing Australia’s regional jobs and use of natural resources. With domestic and international governments pushing for decarbonisation across industries, bioenergy in Australia is not only viable, but essential.




September 2022

Deadline: 22 July 2022

November 2022

Deadline: 21 October 2022


Wind Nuclear energy Gas pipelines Energy efficiency


Grid integration and stabilisation Disruption Embedded networks Biofuels


Microgrids Disaster management Distributed generation


Electric vehicles IoT & cloud communication Demand management


Asset inspection & drones/UAVs



March 2023

Deadline: 20 January 2023

June 2023

Deadline: TBC


Solar Domestic gas outlook Hydrogen and future fuels


Storage and solar Energy networks Safety and risk management Waste to energy


Smart networks Consumer and industrial retail Security


Industrial energy Automation Asset management


Spatial & GIS


Transformers and substations Vegetation management

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June 2022 ISSUE 18

2022 21–23 June 2022 Three virtual conferences: • • •

Future Grids – 21 June Engaging Customers – 22 June Cyber Security – 23 June

Creating efficient and secure future grids and engaging customers in the new digital era.



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