Powerlink will work collaboratively alongside 11 regional NRM organisations, on key aspects including the management of environmental offsets to ensure social and environmental benefits for communities, landscapes and future generations.

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It recognises the opportunity to develop projects across Queensland that support both sectors to be nature positive, while balancing affordability, security and reliability of the electricity network. The partnership also helps to facilitate the successful transition of an electricity network which is becoming more weather affected.

Powerlink executive general manager of network and business development Stewart Bell said, “Powerlink is playing a vital role in delivering Queensland’s transition to a renewable energy future by building the connections between generators and Queenslanders.

“Partnerships like this will also allow us to make meaningful contributions to enhancing Queensland’s natural resources.

“We see this is as not only a way to offset environmental impacts but also to understand how we can do more to ensure future generations can benefit from the rich environment Queensland has to offer.”

Natural Resource Management Regions Queensland CEO Chris Norman said, “The purpose of this agreement is to drive innovation that supports both the energy and natural resource management sector to be nature positive.

“We are hoping to develop a program of collaborative offsets with an initial focus on environmental restoration offsets.

Related article: Endangered parrots arrive at Tasmanian Gas Pipeline

“Like Powerlink, we have a long-term vision for a healthier environment built on foundations of dedication and trust.

“Together we want to develop leading practice around strategic environmental offsets and limit the impacts any action—such as renewable energy projects—might have on the environment.”

The post Powerlink inks NRM partnership for energy transition appeared first on Energy Source & Distribution.

It’s fair to say the energy sector has seen seismic changes since I joined CitiPower and Powercor 16 years ago.

We are witnessing a changing climate, a rise in renewable energy, more and more customers generating and storing their own electricity, and increasing electrification of our homes, industries and transport.

As we continue to shape our plans at CitiPower and Powercor for the next five-year period, engaging with our customers and stakeholders is critical to ensure those plans address customers’ current needs as well as their needs into the future.

Related article: Reports show Victorians want equitable access to renewables

Historically, distributors have depended on formulaic calculations about historical energy consumption and used this to predict future demand.

As we enter the ‘home straight’ of our engagement journey—the most extensive and rigorous we’ve ever undertaken—I have been reflecting on how different this planning cycle has been, driven by the magnitude of the once-in-a-generation energy transition that is underway.

We know that such a major transition poses risks that some may get left behind, so for our 2026-2031 plans we have prioritised innovative and unique engagement methods to reach a broad representation of our customers and stakeholders.

Our goal is to create a compelling vision of reliability and affordability for our customers and stakeholders that paves the way for a future beyond the immediate reset period—and we can only do that with their input.

This reset period has seen us undertake comprehensive qualitative and quantitative research, an iterative feedback loop with customers and stakeholders to ensure our approach evolves as we go, and sharing updates about how the input we’re receiving is shaping our network strategies and investments.

Overwhelmingly, customers are telling us that a resilient and reliable electricity network that can withstand the effects of climate change is a top priority.

We recently asked Powercor customers how much they would be willing to pay for different network improvements—a first for an energy distributor. The value that customers placed on improving network resilience was over $86/kWh.

Customers also quantified the value of improving reliability for the worst-served communities as $71.26/kWh. What this all tells us is that customers are willing to pay for improvements that will benefit everyone.

We’ve also targeted hard-to-reach customers as well as voices from across the range of metropolitan and rural customers and businesses that are part of our network to ensure that every voice is heard and considered—from dairy farmers to EV enthusiasts, and those who advocate for vulnerable customers. By subjecting our proposals to diverse perspectives, we are ensuring they withstand scrutiny and that no one is left behind.

The recent Australian Energy Infrastructure Commissioner’s Community Engagement Review emphasised the need for more meaningful interaction between the energy sector and communities being impacted by the transition, and the necessity and value of engagement. I support this and would encourage not only the industry but regulators to also engage with the communities they serve.

This year we will continue targeting engagements with key stakeholders and customer groups, through in-depth discussions and seeking feedback on proposed solutions to the specific themes that have been identified through earlier engagement. We will also test these proposed solutions associated costs and benefits with our customers.

Related article: Microgrids for three towns part of Powercor resilience plan

While we will no doubt need to make some tough decisions on what we will need to prioritise, particularly against the backdrop of current cost-of-living pressures, through robust consultation we can ensure everyone has a hand in shaping the future of the energy network. We thank everyone who has participated so far in our many engagement activities and events, and for helping us shape our approach.

The input we’re capturing will inform what the energy sector, specifically electricity distributors like us, need to do to ensure our plans reflect real-world demands, changing conditions and the ability to power the future.

Together, we can shape a future that reflects the diverse lifestyles and needs of our customers and is adaptive to our evolving environment.

The post How customers are shaping our future energy network appeared first on Energy Source & Distribution.

Related article: Ergon crews battle flood to restore power in Queensland

The first of 463 concrete poles was put in place in October 2021 and across 78,037 hours of planning, design and construction activities, crews strung more than 400km of conductor.

Ergon Energy project manager Gary McMillan said crews had constant challenges thrown at them throughout the construction.

“We had COVID-19 restrictions throughout 2021/22, a one-in-one-hundred-year rain event in 2022, procurement and resourcing pressures, and the challenges of working through multiple private properties over a corridor more than100km long, throughout which we had great support from local landowners,” he said.

“It has been a massive team effort to get to the end—from planning and design through to the crews on the ground and our external suppliers—there’s been incredible commitment from everyone involved.”

“The teams led by Kenny Gold and Co-Ordinated by Shane Coonan went above and beyond at times. The team racked up 52,774 hours on the job working away from home. And it wouldn’t have been possible to achieve this project without the support on the ground of Rob Pataki and Charley Taplin,” McMillan said.

“It was a long stint for these travelling crews who had the support of crews from Gayndah, Biggenden, Childers, Toowoomba, Maryborough, and Bundaberg to help tie it all together.”

Related article: Community consultation leads to route change for VNI West

“We can never promise our infrastructure won’t from time to time be impacted by animals or environmental conditions, but this project is an $80 million investment in our rural network and has significantly improved the security and reliability of supply to customers in the Burnett region.”

The post Ergon completes new $80M line between Isis and Gayndah appeared first on Energy Source & Distribution.

Western Power began the private power pole inspection program in 2021 after a fallen pole on private property sparked the 2014 Parkerville bushfires, which lead to the destruction of of 57 homes.

Related article: Western Power’s largest underground project complete

A Western Australian Court of Appeal found Western Power had failed in its duty of care to avoid risk or damage by not conducting periodic assessments of poles on private property.

Western Power has since issued notices to about 1,000 customers, giving them either 30 or 90 days to have their poles replaced or risk having the power disconnected.

“Community safety is fundamental, so if we can’t ensure a safe supply of electricity, we may need to disconnect electricity supply until the pole is safe,” a Western Power spokesperson told ABC News.

Many owners have been surprised to discover are legally and financially responsible for these power poles.

“I knew the pole was there, but I thought it was just part of Western Power and didn’t give it another thought,” one resident told ABC Radio Perth.

“Then they sent me a notice saying that it was recommended that the pole be replaced. The average quote comes in around $5,000.”

Western Power asset management executive manager Gair Landsborough told ABC Radio Perth that approximately 80% of the 150,000 private power poles in Western Power’s network had been inspected, with the final 20% due to be checked by early 2025.

“Typically, what we recommend if you get a notice like that is to engage a professional electrical contractor to come in and assess the pole and give you options about replacement if that is required,” Landsborough said.

He said disconnecting the power was a “last resort” when a pole was considered at high risk.

Related article: Charges laid against Western Power for Wickepin bushfire

“If you get a 30 or 90-day [notice] that’s quite a high-risk condition that means, if it’s a wood pole, it’s either got termites or rot. If it’s a steel pole, it’s actually corroded at the bottom and presents a real risk.

“We’ve had very few cases where power has actually been disconnected.”

Read the full story here.

The post Western Power issues notices for private power poles appeared first on Energy Source & Distribution.

It’s the economy, stupid” was a phrase coined by James Carville in 1992, when he was advising Bill Clinton in his successful run for the White House. And here it is paraphrased to focus on the quintessential feature of system strength for the national grid. It was always thus but now, as the nation transitions to very high renewables, it doesn’t earn a guernsey with the state and Commonwealth energy ministers.

Related article: CIS—a Calming In (electrical) Storms?

Of course, AEMO publications on system strength are available to one and all but they make for sleep-inducing reading. And to all intents and purposes, its tortuously worded, highly technical language insulates the decision makers in the national grid from the important message and the risks to system strength the transition to renewables is posing. High or low electrical energy prices, nuclear, hydro, more or less wind or solar considerations pale into insignificance when compared to system strength. Without system strength, we do not have a reliable national asset. In essence, whatever the weather conditions, whatever instantaneous power demand, we need our electricity at the correct voltage, not at some other value where things burn up, or motors stall—and we need it 24/7, i.e., we require system strength. The media is filled with hyped-up arguments put up by both proponents and detractors of solar, wind, coal, gas, etc., and the stern warning “no transition without transmission” but not a word about system strength.

In a nutshell, the national problem is that we have no market for system strength. We do have one for energy—but system strength? System strength evades us like drops of mercury when it comes to a marketable commodity. Yes, there are complicated rules as to who forks out for synchronous condensers on REZ buses, but there is so much more that simply ‘falls off the desk’. Many electrical engineers as well as many in the public at large worry about coal-fired generation shutting down while RenewEconomy and its readers shout hurrahs with every announcement of a big battery, new wind farm project, and so on. Oh, system strength being impaired as a possible result? That’s someone else’s problem. However, sheeting the culpability for waning system strength to the transition to renewables is to trivialise the problem statement. There is hard yakka to be done engineering-wise that could ensure both large penetration of renewables AND system strength. That said, persisting with the requirement that 82% MUST be renewable generation by 2030 is, well, stupid!

What is necessary is an engineering review, in particular, of the south-eastern grid ‘plugging in’ inverter-based resources, be they voltage-forming or grid-following IBR. Obviously that process is to be done in an engineering model of the grid and involves extensive computer-based studies in PSSE. For the cognoscenti reading this article, the afore studies are not to be confused with AEMO’s PSCAD-version 5, which seems basically used to make connection applications of new generation as hard as possible. The erstwhile Energy Security Board, now replaced by a clique of energy ministers, tried in vain to warn AEMO about its Integrated Systems Plan two years ago. It didn’t use the words ‘systems strength’ but said in its critique of the ISP that the planned withdrawal speed of synchronous generation was too fast. Too fast for the preservation of system strength, the ESB could have said, but it didn’t come down to using electrical engineering language.

AEMO uses complex descriptions of system strength. However, in plain language sufficient system strength in addition to the availability of voltages within specifications, everywhere in the grid, requires that no section of the grid be ‘cast off’ unless it can take care of its own power demand and can smoothly reconnect again to the bulk of the grid system. The key ingredient in system strength, given the humongous transmission line lengths already in existence and being planned, is the availability of sufficient reactive power. The illustration and accompanying text in Figure 1 provide an explanation of what reactive power is.

Without the ability to supply reactive power, the grid experiences voltage collapse, and breaks up! Renewable sources of energy are light-on in being able to provide enough reactive power whereas conventional synchronous generation has little or no problems by comparison. The longer the transmission line, the more reactive power in addition to real or usable power required by energy consumption centres at the far end, has to be delivered. Plainly put, we have relied on the remaining synchronous generation capacity to do the reactive power heavy lifting and there is no ‘plan B’ to have this capacity in place for the renewable transition. The principal reason is that there is no reactive power capacity market! We have some markets that kind of work in that direction like the Reliability and Reserve Trader scheme, but problems aren’t solved by nibbling the edges around it.

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The strong point to be made is that, with the exception of hydro, solar and wind by virtue of their IBR-connections to the grid have only a fifth to a quarter of the reactive power capacity of synchronous generation. What should we do? First, draw up a central plan scenario in engineering terms and then think about the markets that will be needed to provide system strength. The national engineering plan would be based on the present network, plugging in future power and reactive power capacities based on renewable sources—and then repeating the exercise based on future energy scenarios as per AEMO’s ISP or whatever else might become our national renewable energy goal. This has to be accomplished through the use of engineering models, and not in real life until we are absolutely sure we have a proper grasp of the system strength challenge. That way, we would ensure that transmission links AND connected generation capacity match the power as well as reactive power requirements of distant load buses—in other words, an integrated design with system strength as the central requirement.

The post It’s system strength, stupid! appeared first on Energy Source & Distribution.

“We have more than 500 field crews across Queensland available to support the restoration effort if required,” an Ergon spokesperson said.

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“People in potentially affected areas should be prepared for power outages and registered life support customers are encouraged to have contingency plans in place.

“Cyclones and flooding can cause major and widespread impacts on the electricity network and there may be times when we need to de-energise sections of the network at short notice for public safety and to reduce the risk of more significant damage.

“As winds pick up, tree branches and other flying debris have the potential to bring down powerlines. Any fallen powerlines should be treated as live and potentially deadly. Stay well away from them and report them to emergency services on 000 or call Ergon on 13 16 70.

“We cannot send crews out in cyclonic conditions, but the trucks are ready to roll when it is safe.

“While our crews are ready to respond as soon as it is safe to do so, weather conditions can impact the timeframes for damage assessment, repairs and restoration.

Related article: Ergon and Energex finishing upgrades to four substations

“Safety around the electricity network is our top priority.”

Ergon Energy’s Outage Finder is a useful tool for information on outages and the text view will sort outages by council area, while general updates can be found on Ergon’s Tropical Cyclone Jasper page.

The post Ergon crews ready to take on Tropical Cyclone Jasper appeared first on Energy Source & Distribution.

Over the past three years, the partnership has seen open sharing of collective specialised knowledge and data. It has also delivered targeted research and informed broader research for both organisations to help plan an electricity transmission network that is future fit.

Related article: Redflow batteries installed at BoM radar locations

By analysing weather patterns, forecasts and events, Powerlink can understand how different weather conditions affect the demand for electricity, the performance of the transmission network and the availability of renewable energy sources. For example, when local weather conditions around transmission lines are cooler, more power can be transferred through the system to customers.

The specialised weather data also helps Powerlink to prepare for and respond to extreme weather events, such as storms, cyclones, floods and bushfires, which can damage the transmission infrastructure and disrupt the electricity supply. Weather data helps Powerlink to assess the risks and impacts of these events, implement contingency plans and restore power as quickly and safely as possible.

The new partnership agreement will extend another three years.

Powerlink CEO Paul Simshauser said, “Weather has a very real impact on the high-voltage transmission network, this collaboration allows us to plan better, respond quicker to ensure Queenslanders have access to reliable electricity.

“Access to this specialised data allows us to push energy through the system in a targeted, more efficient way based on local weather conditions.

Related article: Hydro Tas and BoM extend strategic relationship agreement

“Queensland is also exposed to severe climatic conditions and by understanding these trends and working collaboratively together, we can ensure we have a supply system that is optimised and future fit.

“We are proud to be part of this innovative collaboration that harnesses the power of data and technology to deliver better outcomes for Queenslanders.”

The post Eyes on the skies: BoM and Powerlink renew partnership appeared first on Energy Source & Distribution.

The path to the 80-plus percent renewables grid is obscured by wishful thinking—and ‘silver bullet’ solutions. Presently small modular nuclear reactors are the flavour of the month but they might just as easily submerge again.

Amid the public forum noise and political grandstanding, consumers of electrical energy are installing rooftop solar because electricity tariffs keep rising. They might know more than Australia’s energy ministers—or in the alternative, take the sure for the unsure, no confidence in the nebulous promises of better days to come—sometime soon, or maybe never.

Related article: How to design a ‘renewable’ grid

It’s not that an eventual 100% renewable electricity grid is a fantasy. But the way we are going about its construction makes it a fantasy. And gridlock will come about well before the renewable dream is realised, because wishful thinking isn’t now and never was a better alternative to all-encompassing, integrated engineering planning.

What will gridlock look like? Supply chain choke-ups for synchronous condensers to beef up grid system strength, insufficient practical experience with voltage forming inverters, untested grid operational control, ad hoc siting of battery support, for example in remote energy zones, but investment drying up in the face transmission line congestion is equally likely. Let’s face it, there is already a distinct air of investor reluctance, their patience being severely tested by very long delays in connection approvals—lack of grid strength being an oft cited reason.

The frequently stated need for more transmission line construction is not so much a nonsense; the fact being that more is necessary. However, what is escaping us is that electrical infrastructure has to be a system; in other words, a thought through, planned conjunction of generators-transmission lines-increasingly dynamic load centres.

At a recently held four-day workshop on battery energised voltage forming inverters at Monash University, the breathing space necessary for prolonged testing of this relatively new technology was evident.

The necessary test and observation periods might not suit the climate change warriors—those who are caught in the headlights of 82% renewable target by 2030 or the politicians who feel their electoral success depend in its realisation.

Related article: Australian Energy Week: the dichotomy exposed

The national electricity system planning and execution requires centralised engineering—one where all the parts, as cited above, are planned and the execution, supervised and on a time scale appropriate to ensuring reliability and stability.

Political dreams might be destroyed but we would inherit a reliable, renewable grid—and as to energy costs? Who knows? CO2 reduction is not some convenient zero-sum business—and there’s no such thing as a free lunch.

The post Gridlock—and no end in sight to higher energy costs appeared first on Energy Source & Distribution.

Related article: New EV strategy: Can our electricity infrastructure cope?

In partnership with NRMA and as part of the Driving the Nation fund, the government will deliver $39.3 million dollars in funding to build 117 fast EV charging sites to better connect towns and cities and will ensure there is a fast charger approximately every 150km on national highways.

Minister for Climate Change and Energy Chris Bowen said the government was working to improve EV infrastructure by establishing a nation-wide network of fast chargers.

“EVs aren’t just for the cities, and Australians who drive long distances either for work or for holidays should be able to reap the benefits of cars that are cheaper and cleaner to run,” he said.

“We’re making range anxiety a thing of the past. This project will help close the gaps and known black spots in the network and make it possible to drive from Darwin to Perth, Broken Hill to Adelaide, and from Brisbane to Tennant Creek in the NT.”

Related article: Government reveals National Electric Vehicle Strategy

“This national rollout will help put more Australians in the driver’s seat of cheaper and cleaner cars,” Minister Bowen said.

The post Government teams with NRMA on EV charging network appeared first on Energy Source & Distribution.

CitiPower, Powercor and United Energy are offering third parties an opportunity to develop and implement solutions that can alleviate capacity constraints on the low-voltage network during peak demand periods.

A full tender seeking solutions for more than 240 sites is now open.

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With homes and businesses using more electricity during hot summer days, pressure may be placed on parts of the local electricity network. At times, this can lead to a reduction in reliability and increase the possibility of power outages.

Traditionally, networks invest in upgrades or new infrastructures to accommodate peak demand during just a handful of days. However, smarter technology solutions are now providing networks with more cost-effective ways of managing peak demand without the need for upgrades.

CitiPower and Powercor head of network planning Andrew Dinning said it was the first time all the three networks had opened their low voltage network up to third parties to provide solutions to address capacity constraints that could limit supply or reliability.

“Extreme temperatures, heatwaves and customer growth can place pressure on our networks as more people rely on electricity to stay comfortable at home or work,” Dinning said.

“As a distribution system operator, we want to access existing capability and create new markets to help us manage peak demand in the most cost-effective way for our customers.

“We’re expecting this tender to spark innovative ideas from market participants on both the supply and demand side.”

Non-network solutions may include embedded generation such as grid-connected or behind-the-meter battery storage or other demand management solutions and resources.

The projects will predominately support residential customers and will need to be operating by November this year. Detailed data and locations of the selected sites have been released to the market.

Related article: United Energy takes to the skies for inspections

“This is an important step in developing the capability for publishing data on network capacity and constraints that can enable a whole range of new, creative energy solutions for customers as the energy market transforms,” Dinning said.

As distributed system operators, the networks have been using demand management programs to address areas of network reaching their capacity limits for a number of years. Additionally, United Energy is trialing pole-top batteries to manage peak demand on its network, while Powercor is investing in a community battery that is expected to be in place later this year.

The tenders and site locations are available at United Energy and CitiPower and Powercor.

The post Networks encouraging competition to support capacity appeared first on Energy Source & Distribution.

Intelligent Grid New Technology manager Michelle Taylor said the first low voltage static synchronous compensators – commonly known as a statcoms – were installed in Mossman in May and would continue to be rolled out to other parts of regional Queensland.

“This is an Ergon initiative that will assist the network, which was designed in an era of one-way power flows, to adapt to the rapidly changing network environment where many homes and businesses are both consumers and exporters of power,” Ms Taylor said.

Ergon is working with Statcom Solutions, a Queensland-based company that has won the tender to supply the statcoms, for the rollout.

“Queensland has one of the highest rates of solar PV penetration of any state in the world with more than 140,000 systems connected to Ergon’s grid,” Ms Taylor said.

“This has resulted in some sections of Ergon’s network reaching their acceptable voltage limits due to rising voltage levels caused by solar PV systems.

“Statcoms regulate the voltage on sections of the network where they are installed, enabling more households to feed solar power into the grid and managing peak load voltages also.

“While statcoms are not a new concept, Ergon’s innovative application of the technology uses small-scale statcom devices to help manage the low-voltage network.”

Ergon’s technology innovation engineers delivered a proof of concept for the statcom equipment in 2014 and successfully trialled test versions of the technology in 2015.

“This contract provides our company with the opportunity to expand our product development program and the confidence the technology is accepted in the industry as a tool to improve power quality,” Statcome Solutions sales and marketing general manager Devern Hill said.

“Moving forward, we are positioning ourselves to have the ability and local manufacturing capacity to increase the manufacture of power electronics in-line with our product development roadmap.”

The post Ergon rolls out innovative solar technology appeared first on Energy Source & Distribution.

The procurement is part of a plan to defer more than $236 million of network investment – the largest capital expenditure deferral by non-network solutions in Australian history.

The network’s Powering Sydney’s Future project is designed to reinforce the power supply to the inner city as cables supplying the area reach the end of their technical life and need to be retired.

As part of a proposal approved by the Australian Energy Regulator (AER) earlier this year, TransGrid will defer investment in a new 330kV cable construction by procuring a variety of demand management solutions to reduce the risk of unserved energy to consumers in Sydney as existing infrastructure reaches the end of its serviceable life.

TransGrid energy services manager Rachele Williams said the company had been encouraged by industry and stakeholder feedback in the lead up to the tender process.

“We have seen a very strong response from non-network proponents in our early consultation, and there’s a lot of potential for deferring the commissioning of network infrastructure through the use of non-network solutions,” Ms Williams said.

“In particular, we’re interested in non-network solutions to manage electricity demand to reduce risk in inner Sydney during summer heatwaves.

“We’ve seen a range of options from renewable generation, load curtailment, demand response, and battery storage solutions.

“As far as we are aware, this is one of the largest capital expenditure deferrals by non-network solutions in Australia to-date.”

TransGrid’s tender process will run in two stages, allowing flexibility to procure more demand management should demand forecasts or cable conditions change.

The first stage is seeking 20MW for this coming summer, and 40MW for the next three summers to 2021/22.

The first stage closes July 31. The second stage is a ‘top-up’ round in addition to the first stage, and will seek an additional 20-40 MW for summers 2020/21 and 2021/22.

TransGrid anticipates this stage will commence in May 2020.

The post TransGrid opens 40MW demand management tender appeared first on Energy Source & Distribution.

ENA CEO Andrew Dillon said the 2018 Report Card showed the implementation of the Electricity Network Transformation Roadmap had moved forward in all five priority areas identified since its publication a year ago.

The only area that had not progressed as quickly as network businesses would like was developing the government and sector consensus needed to support fairer energy pricing.

“Better value for money is a priority and further reform is desperately needed if we are to enable the move to a fairer pricing system and save customers billions of dollars over coming decades,” Mr Dillon said.

“We need governments to step up and support networks as we implement pricing that gives our customers the right incentives to unlock savings for all users.”

Developed in partnership with the CSIRO, the roadmap paved the way with practical, forward-looking solutions to address the complex challenges facing the nation’s electricity system.

Setting out 45 milestones and 158 actions, the roadmap provides a clear pathway for network businesses to respond to the evolving environment with the agility, innovation and collaboration required to secure Australia’s energy future.

The five priority areas the Report Card examined were:

•  Improving trust with customers
•  Implementing new services to achieve system security
•  Securing a stable carbon policy
•  Incentivising efficiency and innovation
•  Developing essential information tools for a more cost effective grid.

One year on, the snapshot review found significant work had been done to strengthen collaboration between networks and other key stakeholders to ensure greater information sharing to better meet customer needs.

One key project being developed with the Australian Energy Market Operator (AEMO) will deliver Open Energy Networks, a guideline for integrating new technologies such as batteries and solar into a modernised grid.

Cyber security capability has also been prioritised by networks, with further innovation expected in the next 12 months to deliver additional Finkel recommendations supporting the continued protection of Australia’s critical energy infrastructure and systems.

“Overall, I commend Australian energy networks for the significant progress made in such a short time,” Mr Dillon said.

“However, we certainly can’t be complacent. More work needs to be done – particularly by government on tariff reform – but I know energy networks will continue to work together, with government and with our customers to build a smarter and more affordable energy future for all Australians.”

The post Australia’s energy transformation: network report card appeared first on Energy Source & Distribution.

The AER’s decision allows ElectraNet to recover $1603.2 million over the 2018-23 regulatory period, a reduction of 7.8 per cent ($135 million) on ElectraNet’s original proposal.

ElectraNet CEO Steve Masters said the AER’s decision to accept the company’s proposed expenditure forecasts would reduce the transmission component of the average electricity bill in 2018-19 by $17 for a residential customer and $33 for a typical small business customer.

“Throughout the regulatory process we have been focused on identifying ways we can deliver price reductions for customers while ensuring we provide a safe, secure and reliable power supply,” Mr Masters said.

“The final determination by the AER is great news for consumers because it approves our proposed reduction in transmission charges and associated expenditure reductions, while maintaining service levels for customers.

“This includes a 39 per cent reduction in our capital expenditure and a 9 per cent reduction in our operating expenditure.”

Mr Masters said comprehensive engagement with customer representatives and stakeholders throughout the regulatory process played a central role in helping develop ElectraNet’s revenue proposal.

“Throughout our engagement, South Australian power customers told us that they expected affordability, reliability and choice when it came to their power supply, which shaped our plans and proposals,” Mr Masters said.

“Over the next five years customers can be confident our power supply meets these expectations while also allowing us to manage the growing challenges of a changing electricity generation mix.”

Every five years ElectraNet submits a Revenue Proposal outlining the program of work and forecast revenue needed to operate and maintain South Australia’s electricity transmission network to the AER.

AER board member Jim Cox said the AER accepted most aspects of ElectraNet’s proposal, and welcomed the company’s engagement with its customers during the determination process.

“Affordability is a concern for households and businesses, and customers need to be confident that they are paying no more than needed for safe and reliable electricity,” Mr Cox said.

“We assessed ElectraNet’s original proposal as reasonable and this final decision bears out the value of the extensive consultation it undertook with its customers.”

The key differences between ElectraNet’s original proposal and the AER’s final determination revolve around technical financial matters where the AER applies a consistent approach across all network decisions: the rate of inflation and the value of imputation costs.

This determination is ElectraNet’s first since the “black system” event in South Australia on 28 September 2016, which resulted in a state-wide loss of electricity.

ElectraNet proposed an increase in capital expenditure (13 per cent) in response to the black system event to improve the security of the transmission network and increase its resilience to extreme weather events, which the AER accepted.

The new regulatory period commences on July 1.

The post AER decision delivers stable transmission costs in SA appeared first on Energy Source & Distribution.