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AGL Energy , a publicly–listed Australian company, provides energy products and services to the Australian economy. The company is involved in both the generation and distribution of electricity for residential and commercial use.AGL Energy generates electricity from power stations that use thermal power, natural gas, wind power, hydroelectricity, and coal seam gas sources. The company began operating in Australia in 1837 as The Australian Gas Light Company and claimed in 2014 that it had more than 3.8 million residential and business customer accounts across New South Wales, Victoria, South Australia and Queensland. It has large investments in the supply of gas and electricity, and is Australia's largest private owner, operator and developer of renewable energy assets. Wikipedia.


News Article | April 22, 2016
Site: http://cleantechnica.com

A ground-breaking study involving leading utilities and the Australian Renewable Energy Agency has suggested that Australia’s largest battery storage array could be installed at a South Australian wind farm. The study – Energy Storage for Commercial Renewable Integration in South Australia (ESCRI-SA) – looks at a range of possibilities for non-hydro storage in South Australia and concludes that a 10MW, 20MWh lithium-ion battery storage facility next to the 91MW Wattle Valley wind farm on the Yorke Peninsula is the best option. It is not yet clear that the project will go ahead in that form – questions about financing, the economics of the project and the ability of ARENA to maintain grant funding have yet to be resolved – but it seems certain that the project will go ahead in some form, possibly as a reconfigured 30MW, 8MWh facility. South Australia finds itself at the cutting edge of the world’s shift to renewable energy, with its wind farms and rooftop solar expected to account for around half of total demand by the end of the year. While the Australian Energy Market Operator says this should pose no problems for the local grid – even after the closure of the state’s last coal-fired power station within a few weeks – eventually battery storage will have to be integrated into the grid to ensure stability. “There is no better place to demonstrate this than in South Australia, which has world leading levels of intermittent wind and solar PV generation relative to demand,” the study says. Within a decade, rooftop solar may account for all demand on some days, and there is another 3,000MW of wind projects in the pipeline. The 368-page ESCRI study – partnered by ElectraNet, AGL Energy and Worley Parsons – says that while there are no immediate problems, there is a sense of urgency because battery storage is emerging quickly and the market is simply not prepared. “It is hard to see a long-term future which does not involve energy storage in some form,” it notes, adding that the issues arising in South Australia are likely to emerge in other states as renewable energy penetration increases; meaning reliance on traditional inter-connector network solutions may become less effective. ARENA admits that the report’s conclusions around the economics of the project were disappointing, because it found that it would need grant funding of around $14 million, or nearly two-thirds the cost of the project. But it, and the consortium members, expect this to turn around soon. For one, the discussions with the battery storage industry found that the market is still very immature, and battery storage is a complex business. In other words, the battery storage industry is still learning how to configure its gear to suit the network and its major players. Secondly, the costs of battery storage are expected to fall quickly, with nearly all of the battery storage providers indicating that prices would fall by half in the next few years. Thirdly, and perhaps most significantly, is that the market for services that battery storage can provide to the network is also immature. These services include balancing the output of wind and solar farms, keeping the lights on in a blackout, reducing transmission losses, and providing frequency services to keep the grid stable. Once these services are better understood, and better valued – and this might need adjustments to regulations and market signals – then the economics of battery storage are likely to be clear. Indeed, the report notes that frequency control – and the ability to keep the lights on in the event that the state’s interconnector to Victoria goes out – could be critical. It says that one project is not enough to do this job, but if enough energy storage devices were installed, then this could reduce market fuel costs (from gas generators, for instance) and avoid the loss of all supply to grid-connected consumers. This is particularly important, in light of the state’s recent black-out and the problems created by fossil fuel generators in the attempted re-start. Certainly, the consortium members are keen for the project to go ahead, and say that without it, Australia might be left behind just when it should be seizing the opportunity of leading the pack. “Unlike Australia, other countries have particular policy drivers which are leading to storage take-up, with motives likely to include the lowering of integration costs of renewables, the gaining of experience with a likely disruptive technology and the driving of a local energy storage industry,” the study notes. It cites the Californian Independent System Operator (ISO), which operates in one of the most active energy storage markets driven by its policy mandate for more than 2GW of battery storage, designed specifically to ensure it keeps on top of renewable integration. “In the absence of such policy drivers and any current roadmap, Australia must make prudent investments to keep pace,” the ESCRI report notes. “This also supports the case to continue exploration of the storage product but provides more incentive to maximise the business case – that is, leverage the most from that investment.” Wattle Point and the nearby Dalrymple sub-station was chosen because it is a kind of microcosm of the state’s grid. It’s at the end of the network, it has large penetration of renewables, and there is a possibility of it being “islanded” – meaning that it will rely on local resources, including battery storage, to keep the lights on. It also offers advantages to both ElectraNet, which runs the main transmission line, and AGL. Assets owned by distribution network SA Power Networks were not considered, even though areas such as Kangaroo Island and Victor Harbour could also be suitable. Expressions of interest from 42 international parties were received, and 17 formal proposals, including technologies such as lithium-ion, sodium-sulphur and advanced lead acid batteries; molten salt heat storage; hydrogen generation and storage; and a number of different flow batteries. Project sizes ranged from 10-20MW and 20MWh to 200MWh. In the end, the consortium crunched the numbers in a detailed study of a 10MW- 20MWh lithium-ion project at Dalrymple. As for the next stage, the project partners are keen not to reduce the scale of the project too much, otherwise it will limit its impact, and may not allow the parallel services of market and network value to be realised effectively at the same time. It may not even choose lithium-ion, but rather a hybrid of energy storage technologies through a single interface, if available. “The consortium remains agnostic to which energy storage technology is used and will pursue that which delivers the optimum business case, although the project is really more about application than technology.”   Drive an electric car? Complete one of our short surveys for our next electric car report.   Keep up to date with all the hottest cleantech news by subscribing to our (free) cleantech newsletter, or keep an eye on sector-specific news by getting our (also free) solar energy newsletter, electric vehicle newsletter, or wind energy newsletter.  


News Article | August 22, 2016
Site: http://www.renewableenergyworld.com

AGL Energy Ltd. plans to announce a program within a few months to roll out about 1,000 energy storage systems for Australian homes with rooftop solar panels amid forecasts that falling prices will stimulate demand.


News Article | September 2, 2016
Site: http://cleantechnica.com

Some utilities may think that it will be up to a decade before there is a mass market uptake of battery storage, and the chair of the Australian Energy Market Operator may even try to convince themselves that the technology won’t be commercial for another two decades, but they might be kidding themselves: New research suggests that the cross-over point between the value of solar and storage and grid prices for Australian households may occur within one year. That, at least, is the conclusion of research from Curtin University’s Jemma Green and Peter Newman, which suggests that the A1 tariff – the standard tariff offered to households by state owned retailer Synergy in West Australia – will become more expensive than the combined value of rooftop solar and battery storage some time in 2017. The graph was presented on Tuesday by David Martin – Green’s fellow executive in the solar trading start-up Power Ledger, which is using blockchain technology (the software behind Bitcoin) to trial solar sharing business models in Perth. “That price crossover – the point where the A1 tariff is equal to the value of energy from solar and tariffs happens next year …  next year,” Martin told the Energy Disruption conference in Sydney co-hosted by RenewEconomy. He said that did not meant that people were going to “leap off the grid” in big numbers straight away. That’s because when that point is reached there are “intangible benefits” of being connected to the network, and it would cost a lot more to install enough batteries to deal with the consumer’s demand peaks, or days of cloudy weather. “But as soon as these lines diverge by a significant amount – and overtake the benefits of being connected to the network, then what happens?” The answer, he pointed out in another graph, is a big problem for the utilities that make their money from supplying power to households, because a lot of that demand will now disappear from view, and go “behind the meter.” Martin says a home with a 4kW array might still use the grid for most of the time – meaning that only 45 per cent of the load is “hidden” from the network behind the meter. But with battery storage, the rate of “load defection” – as opposed to grid defection – was likely to increase to the high 90 per cent levels in some instances (see graph above). Those households will only be tapping into network for a small amount of their energy needs. This, of course, has major implications for network business models – particularly their revenue source – and for other consumers. Networks, Martin says, will have to face losing $100 million in revenue in West Australia for instance, or load 20 per cent more grid costs on to other consumers to protect their revenues. Hence, Martin says, the need for completely new ways of thinking about network use, and of sharing solar energy and battery storage. That’s what Power Ledger intends to do with its shared solar model – it allows those with solar and storage to share their power with those who maybe don’t have it – and allows better utilisation of the grid. It also requires, he says, a completely new way of thinking about regulations. The rules governing the electricity industry had been framed without any consideration for sharing energy, for storing energy, or for the kind of technology that his company proposes. Martin was not the only person talking of an imminent tipping point in the economics of battery storage. Stefan Jarnason, the founder and head of Solar Analytics, a monitoring company partly owned by AGL Energy, says he believed that even some of the more bullish forecasts for battery storage were too conservative. These included predictions – from the likes of Bloomberg New Energy Finance above – that some six million households will have energy storage by 2040. Jarnason says that this shows that massive uptake is inevitable, but it is the speed that counts. He notes there there are already 1.6 million homes with rooftop solar, and around one million of these would soon be paid “visually” nothing for the vast majority of their rooftop solar production that is exported back to the grid. Most premium tariffs end at the end of the year in NSW, Victoria and South Australia. “We talk to those customers and they are not very happy about that. They love the fact that they have solar, they feel a bit green, a bit financially savvy, even a bit smug, but they already have got their money back on solar and they are now looking to do something extra.” That estimate is backed up by experience from one of the many battery storage providers moving into the Australian market. Enphase Energy, which is launching its first battery storage product in Australia, says more than half of the 72,000 units of its 1.2kWh battery has come from NSW, where generous feed in tariffs come to an end at the end of the year. “The energy storage revolution is going to come much faster than a lot of people imagine and a lot of people are prepared,” Jarnason says. “Residential solar plus storage is going to eat the energy world.”   Drive an electric car? Complete one of our short surveys for our next electric car report.   Keep up to date with all the hottest cleantech news by subscribing to our (free) cleantech newsletter, or keep an eye on sector-specific news by getting our (also free) solar energy newsletter, electric vehicle newsletter, or wind energy newsletter.  


News Article | March 29, 2016
Site: http://www.topix.com/energy/alt-energy

Dominant gas pipeline owner APA Group has stepped up the pace of its acquisitions again with a $151 million deal to buy AGL Energy out of their jointly owned Diamantina power plant in Queensland, a transaction foreshadowed by Street Talk earlier this month. The transaction, which comes as AGL Energy sheds non-core assets and increases its focus on retailing and customer-centric businesses such as solar power, has enabled APA to upgrade its earnings guidance for the full-year.


News Article | March 17, 2016
Site: http://cleantechnica.com

The 46,000MW of black and brown coal fired generation currently in service in Germany will be worthless in little more than a decade if the country adopts the targets embraced at the Paris climate change conference, a new analysis from Barclays says. The analysis, from leading energy analyst Mark Lewis, says coal fired power generation would have to be almost completely eliminated by 2030 in a scenario that would require a substantial carbon price (€45/t) and the end to the current energy market design. The conclusions of the report should not be a surprise, but are important because the fossil fuel industry appears to remain in complete denial, hoping that the Paris climate agreements amount to a “fell-good” gathering that will have no follow through. But the latest data on soaring global temperatures, and the biggest jump in greenhouse gas emissions on record, suggests this hope is misplaced. Or at least should be. The analysis has implications too, for Australia, which faces a similar transition to Germany, which a growing level of renewables on top of a huge surplus in coal generation, and no effective carbon price to influence energy choices. Even the most ambitious fossil fuel generators in Australia, such as AGL Energy, say their coal assets, particularly their brown coal assets, will continue generating as late as 2048. The Barclays scenario shows that this would be impossible. Indeed, The Climate Institute says all coal fired generation must cease by 2035 at the latest. But back to the Barclays report. It suggests that coal will have to be displaced to meet greenhouse gas targets embraced by the EU and implied by the Paris agreement. In Germany, under current policies, total generation will reduce by 15 per cent under energy efficiency measures and its target for 50 per cent renewables. To meet the emissions goals, however, that remaining fossil fuel generation will have to come nearly exclusively from gas, meaning a carbon price is required to upturn the “merit order”. Currently, the lack of a carbon price and the presence of cheap coal means that gas fired generation is marginalised. Lewis says by 2030, Germany will have dumped its energy system- where a plant is longer dispatched on the basis of its relative cost for the next half hour – and replace it with one where renewable generation is backed up by energy storage and sophisticated demand-side responses facilitated by smart-grid technologies. “It will still be some time before we reach that world and before the last half hour of competitively priced power is dispatched,” he notes. But he says this will occur, which is why the biggest utilities in Germany, E.ON and RWE, have decided to split their assets into new and old companies, jettisoning their old “centralised” generation assets to focus on a new business centered around solar, storage, smart grids and electric vehicles. “The Energiewende requires a complete strategic reprioritization away from conventional generation and towards renewable energy so that the companies can prepare for the power system of the future,” Lewis says. He believes that only a handful of coal plants would still be operating by 2030 – the Datteln 4 (1.1GW) and Maasvlakte 3 (1.1GW), and the Westfalen E (765MW) hard coal plants, all of which have very high efficiency rates of 46 per ent. The only lignite plant still running would be the BoA 2 & 3 units at Neurath (2.1GW), which have a very efficiency rate for lignite plant of 43 per cent. The value of the brown coal generators for both E.ON and RWE would be wiped out completely, and considerably reduced for hard coal. The value of gas-fired generation, though, would increase. Barclay’s base-case scenario assumes current targets, an average baseload power price over 2020-30 of €28/MWh in real terms (constant 2019 €), and an average EUA price in real terms of only €5/MWh. Its 2°C scenario would require an average EUA price of at least €45/t in real terms (constant 2019 €) and hence average baseload prices of €55-60/MWh (again in constant 2019 €) over 2021-30. By 2030, total coal and lignite output in the entire German market is only 50TWh (versus 190TWh in our base case) while total German gas-fired output in 2030 is doubled from the base case to 150TWh. “The implications of our analysis … of the German power sector – especially when taken together with Germany’s own 2030 targets for energy efficiency and renewable energy – are that very little coal and lignite could run by 2030,” Lewis writes. Gas displaces coal and lignite over the decade while coal and lignite plants see lower average utilization rates and shorter average operating lives, with what little plant is running by the end of the next decade pushed to the margin. Reprinted with permission.    Get CleanTechnica’s 1st (completely free) electric car report → “Electric Cars: What Early Adopters & First Followers Want.”   Come attend CleanTechnica’s 1st “Cleantech Revolution Tour” event → in Berlin, Germany, April 9–10.   Keep up to date with all the hottest cleantech news by subscribing to our (free) cleantech newsletter, or keep an eye on sector-specific news by getting our (also free) solar energy newsletter, electric vehicle newsletter, or wind energy newsletter.  

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