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 | May 11, 2017
Origin Energy has set a stunning new benchmark for renewable energy off-take deals in Australia – and sounded the alarm for energy incumbents – after committing to a long-term power purchase agreement of below $60/MWh for the 530MW Stockyard Hill Wind Farm in Victoria. Under the terms of the deal, Origin will sell Stockyard Hill Wind Farm – Australia’s largest wind development – to Chinese company and wind turbine manufacturer Goldwind for $110 million. At the same time it has agreed to buy all of the power generated by it, and the associated Renewable Energy Certificates, for less than $60/MWh, from the commencement of operations in 2019 to 2030. RenewEconomy understands that the strike price for the wind farm output is “well below” $60/MWh and closer to $50/MWh than $60/MWh. As such, it sets a new benchmark for renewable energy prices in Australia, and its impact should not be underestimated. It is, after all, around half of the wholesale price and comparable to what could be bought directly from a brown and coal fired generator. It compares with the AGL deal to pay just $65/MWh for the output of the Silverton wind farm in the first five years, which beat the previous low price of $73/MWh price struck in the ACT wind auction for the Hornsdale wind farm, although that price was fixed for 20 years, with no inflation uplift. Origin Energy CEO Frank Calabria says it indicates just how fast Australia’s renewable energy transition is unfolding. “Through our deal with Goldwind, Origin has been able to add a substantial amount of new renewable energy to our portfolio at a market leading PPA price. “And, as Stockyard Hill is in Victoria, this will help to cover a large portion of the load of the recently retired Hazelwood Power Station,” Calabria said. “As Origin looks to a future where renewables will dominate Australia’s energy supply, we are in a very strong position to build one of the nation’s lowest cost renewables portfolios.” Origin has signed a slew of PPAs with wind and solar farms in recent months, including the 110MW Darling Downs solar farm – located adjacent to its large gas generator – which it sold to APA last week. It has also signed contracts for three other solar farms – including the 220MW Bungala solar farm in South Australia and has two more large contracts in the pipeline. Origin, like the other retailers, are expected to shoulder the bulk of the efforts to meet Australia’s renewable energy target of 33,000GWh by 2020, which roughly equates to around 23.5 per cent of total demand. Origin is indicating that it can go further, courtesy of the plunging cost of wind and solar. “By 2020, we expect that renewables will be more than 25 per cent of the energy in our generation mix, allowing us to deliver the cleaner energy our customers want,” Calabria said in a statement. “Last year, we announced our ambition to add up to 1,500MW of new renewables by 2020, and we are now just 300MW short of that target.” Last week, the Clean Energy Regulator said that despite fears to the contrary, the RET was likely to be met, given the huge rush of contracted projects in the last six months, particularly in solar. It says there may be enough commitments made by the end of the year to meet that target. Some doubt that, worrying about the retailers’ appetite beyond the current rush of projects, but Origin’s comments appear to allay those fears. While recent investment has been centered around large scale solar farms, whose costs have fallen dramatically in the last year, the Stockyard Hill deal shows there are still great deals to be found in wind energy, and wind energy costs are still falling. It also suggests that Origin will have to update this graph to the right that it released last week, which highlighted the plunging cost of wind and solar PPAs in Australia over the last few years. Note how Origin make it clear that renewables are the lowest cost new build generation today -it’s not coal, it’s not gas, and it’s certainly not nuclear. Indeed Origin, like AGL Energy, has now dismissed the idea that gas fired generation can play any significant role in the energy transition, with Calabria telling investors last week that only gas peaking plants will play a role, and that they will be “even peakier” than they have been, suggesting they will be used less and less as more wind and solar and more storage is installed. The Stockyard Hill deal, announced on Monday, remains subject to regulatory approvals and still hinges on Goldwind achieving financial close of the project. That financing shouldn’t be an issue, given that Goldwind is one of the biggest wind turbine manufacturers in the world and is currently building the 175MW White Rock wind project in Barnaby Joyce’s electorate, and is building it without a contract and on a merchant basis. Environment Victoria’s Mark Wakeham said it was clear that the finance industry had decided that renewable energy was the future, but warned that deployment would grind to a halt unless the Turnbull government extended the national renewable energy target and the Victorian government legislated the state renewable energy target. “To meet our national 2020 renewable energy target, all projects will need to be underway this year or next. After that, investment in renewable energy projects could fall off a cliff without longer-term targets.” Check out our new 93-page EV report. Join us for an upcoming Cleantech Revolution Tour conference! Keep up to date with all the hottest cleantech news by subscribing to our (free) cleantech daily newsletter or weekly 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 | May 18, 2017
Have you heard the line recently that grid-based battery storage is “coming”, but is not quite “commercial”, but might be in a few years time, or even a decade or two? It’s a common misconception. But if you wondered about the overwhelming response to the recent tenders by South Australia and Victoria for the country’s largest battery storage installations, here’s why: The technology is already in the money. That, at least, is the estimate of Bloomberg New Energy Finance analyst Kobad Bhavnagri, who says that battery storage is not just in the money, it is a long way into the money in states like South Australia, already with a high level of wind and solar and volatile wholesale electricity prices. “We’ve seen the price of battery packs as fallen by 75 per cent by 2010, and our calculations show that will fall by a further 75 per cent by 2030,” due to technology innovation and manufacturing scale, Bhavnagri said. That means that large-scale battery storage is already viable in large parts of Australia. In South Australia, it is offering internal rates of return of around 30 per cent (even without new market rules that will further encourage them), and in Queensland they are also profitable due to that state’s price volatility. NSW and Victoria will follow soon enough. “That is a great story for integrating renewables,” Bhavnagri said. (And we should also point that this value stack for storage does not include network benefits, where battery storage is already seen to reduce cost of upgrades of poles and wires by around 30 per cent). So, what does this mean for the grid? The CSIRO and the Energy Networks Australia gave some insight into this in their report last week, in which they outlined their pathway to a zero emissions grid based around solar, wind and storage, and why it would be much cheaper, cleaner, smarter and more reliable than the current iteration. AGL Energy gave its own version of the future this week in a presentation to a Macquarie Group conference. As we reported earlier, the company once known as Australian Gas Light no longer sees gas as a transition fuel. AGL says the economics of gas-fired generation don’t stack up, because wind and solar and storage are cheaper, and major gas producer Santos this week gave us an insight into why gas has little credibility on the environment front. In his presentation, AGL chief financial officer Brett Redman provided this graph illustrating what has been presume to happen on the left – renewables with gas filling in the gaps – and what will happen with storage. “Fairly quickly, a drive to more renewable energy becomes a conversation about how to time-shift energy using storage,” Redman says. “And once we have the storage capacity to get us to 50 per cent (renewable energy), we will have the technology to go to 100 per cent (renewable energy). “It is just a question of cost and the rate of adoption.” Redman even invited his audience to imagine a 100 per cent renewable energy scenario in the year 2050, just a year or so after AGL closes its last brown coal generator, Loy Yang A. (AGL is working on the assumption that its generator is the last one standing, but the reality is – and it knows this – that Loy Yang A will close well before then). “What we’re starting to think more and more about is, what does such a world look like,” Redman said. Using this table above, Redman suggested that around 200 terawatt hours of renewable energy would be needed for 100 per cent renewables scenario in 2050, which would require around 90GW of renewable generation – around 75GW more than what we have now. And by his calculations, that would require some 350GWh of battery storage. The sums he cited are huge – $150 billion of new wind and solar and $100 billion of battery storage. There would be so many batteries that they would fill some 350,000 44-foot storage containers, and if laid end to end would stretch from Sydney to Perth with plenty to spare. Now, it’s important to note that this is for illustration purposes only. It’s not going to work out like that for a bunch of reasons. Firstly, as Redman admits, the renewables cost estimate is based on today’s prices (of around $2m per MW installed), and these costs will continue to fall dramatically. The second issue is that we may not need that much large-scale wind and solar because we are likely to get a lot more “behind the meter” solar on the rooftops of homes and businesses, paid for by consumers who can save on their bills, as well as a lot of “distributed” storage. Indeed, AGL’s calculations assume only 15GW of rooftop solar by 2050, whereas CSIRO and ENA predict 80GW, providing nearly half of all energy demand. The answer will surely be somewhere in between. The other issue is that we may not need that much storage, let alone battery storage. Demand is likely to shift to meet supply, as new AEMO chief Audrey Zibelman and others have predicted. And while batteries might be good for short-term storage, BNEF’s Bhavnagri notes that it is not so cheap for longer time periods, and so that service will likely come from providers such as pumped hydro, solar thermal, or even hydrogen or ammonia storage for longer time frames. Still, this marks a major turning point in the thinking about the future. Hitherto, the major players were debunking renewables and essentially “talking their book,” which were full of fossil fuels. The stunning cost falls in solar in particular and storage – and the fact that they are now demonstrably and significantly cheaper than new coal and gas – has put the writing on the wall. Now we have the network owners and the major generators and retailers working out how to adapt their business to the inevitable – a switch to 100 per cent renewable energy. It used to be only the environmental NGOs and the think tanks that talked about this – now it is the mainstream energy industry. “The introduction of big storage fundamentally changes the market for electricity and enables the transition to big renewables,” Redman says, adding that the closure of coal will be matched by the building of storable renewable energy. “The bow wave of that change will be all about the cost of storage,” he said. And we can bet it will happen much faster than he is saying. Check out our new 93-page EV report. Join us for an upcoming Cleantech Revolution Tour conference! Keep up to date with all the hottest cleantech news by subscribing to our (free) cleantech daily newsletter or weekly 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
Below are the key takeaways from the week in solar, grid edge, energy storage, and other energy news. $1 The new annual salaries for SolarCity's CEO Lyndon Rive and CTO Peter Rive, reduced from $275,000 per year each. The symbolic restructuring comes as SolarCity announced a net loss of $250 million and planned layoffs, both announced on its earnings call last week. (story) Speaking of SolarCity's earnings call, the company also announced it would begin developing a BIPV product for rooftops. That caught the attention of Eric Wesoff, who this week penned a cautionary letter to the brothers Rive and Elon Musk on the pitfalls of the BIPV market. (story) 65 Megawatts The amount of residential solar capacity that Sunrun installed in Q2 2016, outpacing investor expectations. (story) $0.11 per Kilowatt-Hour The RPS credit for solar customers in Arizona proposed by the state's Corporate Commission. The RPS credit is part of a string of recent pro-solar decisions by the commission, which include the rejection of utility proposals to raise customer rates, implement new demand charges, and reduce net metering compensation. (story) 100-120 Microns The thickness of 1366 Technologies' new "3-D" solar wafer, roughly 80 microns thinner than the industry standard. (story) 52 Megawatts The amount of load that New York utility Con Edison is planning to defer as part of the Brooklyn Queens Demand Management project. This week, Katherine Tweed details the clearing prices and the winning bids from the BQDM auction that took place last month. (story) 20,000 Customers The number of customers in Xcel Energy's Colorado territory that will participate in a new time-of-use rate program in 2017. The program is part of a settlement between the utility, public advocates, and the private sector that avoids proposed grid-use fees. (story) 11 Companies The number of companies that are protesting the California's DRAM auction. According to the protesters, the state's three IOUs did not auction off as many demand response megawatts are they were mandated to by the state's PUC. Jeff St. John breaks down the controversy this week. (story) 1,000 Solar-Plus-Storage Systems The number of residential systems that will be part of a AU$15 million virtual power plant in Australia. AGL Energy is developing the project and it is expected to come on-line in Q2 2018. (story) $1.7 Billion The amount paid this week by advanced water treatment company Xylem to acquire smart meter manufacturer Sensus. (story) 50 Megawatts The cumulative capacity of energy storage projects that are being fast-tracked by SCE and SDG&E in California. The utilities are working at a feverish pace to bring the projects on-line by the end of the year to make up for capacity losses from the impending shutdown of the Aliso Canyon natural-gas storage facility. (story) $1.1 Billion The amount paid by oil and gas giant Total to acquire battery manufacturer Saft earlier this year. This week, Julian Spector looks at how other oil majors can take a page out of Total's playbook and diversify their energy portfolios. (story) Zero Emissions The emissions requirement for new construction in the city of Vancouver, Canada by 2030. Julian Spector outlines how Vancouver intends to execute the ambitious plan -- and its potential costs. (story) 10 Years Old The age of RGGI, the U.S.' first carbon-trading scheme currently adopted by nine Northeastern states. Since its inauguration in August 2006, carbon emissions have dropped 36 percent in RGGI states. (story) 900 Bills The number of renewables-related bills introduced into U.S. state legislatures in 2016. This week, EQ Research gives Squared members a snapshot from a busy year in state-level policy. (story) 106% The percentage of Scotland's electricity demand met by wind power earlier this month as a result of a violent wind storm that hit the country. (story) 43 Days The average number of days it takes to close a home in the Chicago market when energy consumption information is disclosed, compared to 63 days for homes where no energy data is disclosed. This week, Nate Adams of Energy Smart Home Performance presents the argument for making energy an integral part of the real estate market. (story)
News Article | February 4, 2016
AGL Energy Ltd., Sydney, has decided to quit the natural gas exploration and production business, a move that includes walking away from several controversial coal seam gas (CSG) projects.
News Article | April 22, 2016
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 | February 17, 2017
Oh, the irony. NSW is one of the most coal-dependent states in Australia, with renewable energy contributing less than 10 per cent to its electricity mix on average. Over the weekend, however, wind and solar may just have helped keep the lights on. It is now clear that solar (rooftop and large scale) was contributing more than 1GW to the grid during much of the day, and around 500MW in the late afternoon on Friday when the Australian Energy Market Operator had flagged the possibility of rolling blackouts. The strong performance of wind and solar came despite the loss of more than 1GW of capacity of coal fired power and the sudden withdrawal of two of the biggest gas fired generators on Friday afternoon – at the height of the heatwave and supply-demand crisis. NSW energy minister Don Harwin praised all fuels for their efforts, but singled out wind and solar. “It’s the biggest day ever for solar,” he said in a statement, and added there was “plenty of wind power generation coming in from the wind turbines along the great dividing range. That turned out to be useful, even crucial for consumers at risk of blackouts. Two 500MW units of one of the state’s biggest coal generators – Liddell in the Hunter Valley – had gone out of service earlier in the week due to problems with the boiler tube leaks.. That likely contributed to the decision by AGL Energy to cut power to the state’s biggest consumer of electricity, the Tomago aluminium smelter in the Hunter Valley on Friday. The AGL supply contract allows it to do that, That “load shedding” removed more than 300MW of demand, and with the contribution of solar probably saved consumers from the type of rolling blackouts that afflicted South Australia last week when the country’s most efficient gas-generator sat idle. It was a bad week for AGL and fossil fuel generators in general. Not only did Liddell lose half its production, with one unit returning on Saturday after the crisis had passed, a unit of its Torrens Island gas generator in South Australia also failed early last week – on the same day as Liddell. The 120MW capacity from that Torrens Island unit may have helped South Australian consumers, many of them clients of AGL, from losing power last Wednesday in the rolling blackouts or load shedding. Of course, many consumers – particularly those of Simply Energy, may be asking why the Pelican Point gas fired generator – touted as the most efficient in the country, and owned by the same company, Engie, chose to stand idle while they lost power. Or why the Australian Market Operator chose not to instruct it to fire up. But more questions are emerging about the role of gas fired generators in NSW at the height of the supply crunch. Two of them, Colongra and Tallawarra, stopped generating in the afternoon peak on Friday, as these graphs provided by Dylan McConnell, from the Climate and Energy College in Melbourne, illustrate. The 435MW Tallawarra gas station is owned by Energy Australia, owner of the Mt Piper coal plant, which (like all other generators) would have benefited from the $14,000/MWh power prices that occurred after Tallawarra stopped generating. It appears that Tallawarra had a fault that caused it to trip and damage some valves. The 667MW Colongra power station is owned by Snowy Hydro. See our story last week – High power prices? Blame fossil fuel generators, not renewables” of how Snowy Hydro and Origin Energy acted to push up prices in NSW late last year. This is what happened when the two power stations stopped generating. Remember, this is when NSW was facing a supposed critical shortfall, and when the Tomago smelter had been forced to shut its pot lines, risking catastrophic damage and safety issues, according to its CEO. Interestingly, AEMO issued a “non conformance” notice to Tallawarra on Friday evening, apparently because it did not follow instructions. Asked for further details, a spokesman said: “AEMO does not comment on reasoning behind the generator non-conforming with their dispatch instruction as that is an issue for the generator.” Meanwhile, the supply/demand issue remained critical in Queensland on Monday, which was expecting record power demand and potential shortfalls in supply. Rooftop solar also played a critical role in that state over the weekend, when the state hit extraordinarily high levels of demand for a Sunday. Solar vastly reducing the peaks on grid use, as the AEMO warned of supply shortfalls. This graph from Global Roam, providers of our excellent and popular NEM Watch widget, illustrates. The fact that rooftop solar was delivering so much power during the day would have limited the number of price spikes in the state. Notice how the price did not spike until demand fell, and rooftop solar was on a downward trajectory. As we reported exclusively last Wednesday, Queensland prices have spiked more than 40 times more often in South Australia this year and have averaged more than $240/MWh. As ITK analyst David Leitch pointed out earlier last week, the afternoon prices have averaged more than $1,000/MWh. In the last week it averaged more than $450/MWh and over the last 24 hours averaged more than $800/MWh, according to McConnell. The Australian Energy regulator said on Monday that it would investigate eight different spikes above $5,000MWh in NSW and Queensland over the last three days, as it is required to do. Back to NSW, energy minister Harwin said that renewable energy was providing 25 per cent of power needs during some of the daylight hours – when solar was strong and wind also blew, and Paul McArdle notes that it provided around 16 per cent of total production during the 24 hours on Friday. Wind and solar provided more than 7 per cent but could, of course, have provided more but NSW has been deemed the worst place for large scale solar investment. The AEMO provided this data for NSW at peak demand, but note that this is peak grid demand, not total demand, which is disguised from the grid operator because much of the rooftop solar is consumed within the households. (We are seeking comment from AEMO, EnergyAustralia and Snowy Hydro). Buy a cool T-shirt or mug in the CleanTechnica store! 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News Article | December 17, 2016
Originally published on One Step Off The Grid by Sophie Vorrath AGL Energy’s delivery of what would be the world’s largest virtual power plant – in South Australia – looks set to come in “well ahead of schedule,” after the utility announced on Thursday that it had already sold out its first round of 150 connected battery storage systems, with 350 second-phase battery systems now up for grabs. AGL first announced plans to develop the ambitious VPP project in August – a centrally controlled network of 1,000 residential and business battery storage systems with a combined total of 7MWh capacity that would both store rooftop solar power and help manage grid stability in the state. As we reported at the time, the trial comes at a critical time for South Australia, which has come under intense political and regulatory scrutiny as a world leader in the uptake of solar and wind, at the same time as shutting down its “baseload” coal powered generation. The $20 million project is being developed over three phases in conjunction with the Australian Renewable Energy Agency, which has committed up to $5 million in funding to its roll-out. The hardware for the VPP – the 1,000 battery systems – and the energy management software are being supplied by US-based energy management company, Sunverge, which got the job through competitive tender. AGL has said the finished product, which will have an output equivalent to a 5MW solar peaking plant, will work by using a cloud-connected intelligent control system that will allow the batteries to be directed in unison: a strategy aimed at helping both consumers to maximise solar self-consumption, and the broader community to manage state-wide peaks in electricity demand. AGL chief Andy Vesey has said on various occasions that he believes such centrally controlled networks of rooftop solar and battery storage will be a key ingredient of energy systems of the future – systems that will be centred around the consumer. “We want to make sure we have the ability to deploy these all along the grid, where they have value,” Vesey told the Disruption and the Energy Industry conference co-hosted by RenewEconomy in Sydney in late August. “People say it’s innovative, but we know we had to do it… It starts and ends with the consumer, and the consumer will in time be the one that controls the entire system based on the decisions and consumption they mark on a daily basis.” In a statement marking the progress of the VPP project so far, AGL executive general manager of New Energy, Elisabeth Brinton, said the rapid uptake of the first battery offer had put the second round offer – which is now open to applications – well ahead of schedule. “I am pleased that consumers have supported this industry-leading initiative which offers an innovative solution, not only to savings on energy bills, but also to potentially helping stabilise the grid,” Brinton said. “Being a part of the VPP means our customers will be able to consume more energy generated from their own rooftop solar systems, lowering their power bills and reducing emissions.” The 350 batteries on offer in the second phase of the trial will be available to AGL customers who live in Metropolitan Adelaide and meet the eligibility criteria, AGL said. These customers will be able to purchase the Sunverge 11.6kWh battery at $3,849, which includes hardware, software and monitoring services and installation. This battery also includes 50 per cent more capacity than the first offer battery – customers who purchased a battery in the first round will be able to upgrade to the 11.6kWh unit at no extra cost. AGL said it expects customers with “sufficient excess solar generation” to achieve system payback of seven years or less. Customers who don’t have solar, but want to take part in the trial can purchase an appropriately-sized system with their battery. ARENA CEO Ivor Frischknecht said the Agency was supporting the VPP trial as part of its broader objective to make high renewables energy systems more stable, both in South Australia and nationally. “Storing and delivering energy at individual houses means power is available very close to where it’s being used, and that has a range of benefits.” Mr Frischknecht said. “Instead of getting electricity from large power stations outside cities that’s fed across long power lines, sometimes from different states, households can now use power from the sun, captured and stored from their own roofs. Frischknecht said that central cloud-based controls meant that AGL would be able to operate the connected solar and battery systems like a typical power station, with even faster response times, discharging electricity to consumers’ homes during periods of high demand and supporting the grid during periods of instability. “Ultimately, this means virtual power plants could be rolled out across the country to provide reliable, affordable renewable energy to Australians.” But as COAG energy ministers continue to nut out how Australia’s National Electricity Market infrastructure and rules can be adapted to the increasing amount of renewable energy coming on line, Frischknecht also noted that influencing regulatory change was another of the project’s key goals. “It’s important for regulators to see how these systems work in real networks so they can make evidence-based decisions when they’re updating market rules,” he said. Meanwhile, in northern Adelaide, SA Power Networks has quietly installed the last of 100 battery storage systems in its own VPP trial – which the network points out makes it the largest one actually commissioned, for now, in Australia. SAPN said on Thursday it was installing the final battery required for a unique three-year trial involving residential customers in Salisbury, in Adelaide’s northern suburbs; pairing a Tesla battery with a 3.2kW solar system. As we report here, the network operator hopes the trial will help it avoid millions of dollars of costly network infrastructure additions in the Salisbury area. People interested in being involved in the AGL trial or to check their eligibility to the program can register online at agl.com.au/powerinnumbers or call one of AGL’s battery experts on 1300 447 465. Buy a cool T-shirt or mug in the CleanTechnica store! 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News Article | December 7, 2016
Business and environment groups have expressed dismay at the federal government for scrapping consideration of an emissions intensity trading scheme in the electricity sector as part of its 2017 review of climate change policies, just a day after floating the possibility. On Wednesday a range of experts said the abrupt backflip by the environment and energy minister, Josh Frydenberg, on Tuesday night would create further regulatory uncertainty, which was a recipe for higher power prices down the track. But despite chalking up an internal victory by seeing off a carbon price for the electricity sector, conservatives within the Turnbull government are doubling down on efforts to limit future ambition in climate change policy. The South Australian Liberal Cory Bernardi declared Australia should pull out of the Paris international climate agreement, which require it to reduce emissions by between 26% and 28% on 2005 levels by 2030. The Paris agreement is the underlying architecture that locks Australia into pursuing emissions reductions, but Bernardi declared “we don’t need to be part of an international agreement that actually impedes us from making determinations in our own best interest – particularly an agreement that won’t include the world’s largest economy.” Bernardi said Donald Trump’s campaign promise to withdraw from the Paris climate accord “should be the catalyst for Australia to do the same.” The government’s decision to rule out emissions trading came a day after Australia’s electricity and gas transmission industry called on the government to implement a form of carbon trading in the national electricity market by 2022. The report, which was backed by the Csiro, said adopting an emissions intensity scheme for electricity would be the least costly way of reducing emissions and could actually save customers $200 a year by 2030. Matthew Warren, the chief executive of the Australian Energy Council – representing 21 electricity and gas businesses – was scathing about the government’s decision. “Doing nothing is not an option any more,” he said. “We are seeing in realistic terms the warning signs about the degrading state of the electricity grid and that says everything about why we have to have this review process to deliver substantial and meaningful outcomes, because if we don’t the system starts to disintegrate. “Old assets are reaching the end of their lives and there is nothing coming in to replace them. South Australia is already facing that now and it’ll happen across Australia if we don’t do something. “We’re seeing the effects of do-nothing for a long time. It doesn’t make sense to limit the scope before it has begun. We need to use this opportunity to reset.” A spokeswoman for AGL said an emissions intensity scheme would be a cost-effective way to achieve an energy transition, but it would not be enough on its own. “It is important that the Australian energy sector has clear policy settings that are agreed by Coag and consistently implemented across states,” she said. “The results of the AEMC and Finkel reviews and Coag processes will be important to help define future policy settings and AGL Energy encourages governments to move quickly to provide the certainty needed to give confidence to the industry to make significant investments which will improve outcomes for consumers.” The Climate Institute’s chief executive, John Connor, said the developments this week added to the “policy chaos of the last decade” on climate change mitigation. “Ruling out options before this review even begins is irresponsible,” he said. “It will heighten, not decrease, risks to energy security and electricity prices, because it adds further uncertainty to a sector which has already been described by the Australian Energy Council as ‘almost unbankable’ and ‘visibly deteriorating’.” The chief executive of the Business Council of Australia, Jennifer Westacott, stopped short of directly criticising the government but stated support for bespoke emissions reduction policies per sector. Tom Quinn, the executive director of the Future Business Council, described government’s updated position as a “big blow” to its members. “It throws certainly for the entire future business sector under the bus, especially the booming renewables sector and the entire low-emissions sector, so this is a real blow,” he said. “The future is low-carbon, the future is renewables, and the longer Australia delays the more we miss out on economic opportunities and the more we undermine business confidence. “Once again it means we are propping up the businesses of last century at the expense of this century’s growth stories.” Tony Wood, energy director of the Grattan Institute thinktank, said that ignoring the sector-specific scheme would result in higher costs for end users. “The worst of this is that the people who caused the minister to do this are going to get almost exactly the outcome they’re trying to prevent,” he said, citing less certainty in investment with knock-on effects for business confidence. Retailer Energy Australia said it supported a national approach to cleaner energy sources with consumers in mind but resisted the move to rule out policy solutions before the review. “We encourage everyone involved in energy policy to focus on understanding the problems we face in that transition,” it said. Australian Conservation Foundation’s Victoria McKenzie-McHarg said the new position from the government was a “startling” following a statement from the prime minister that heartened her organisation the previous day. “By knocking out policy options this early in the review, the government is just making their task much harder, and the confidence in that process is significantly reduced,” she said. Australian National University economist Frank Jotzo said an emissions intensity scheme for the power sector wouldn’t be perfect, but would be effective. “It is second-best to a standard emissions trading scheme,” he noted. “But limiting the impact on electricity prices is precisely why an emissions intensity scheme has been in the discussion.” The Minerals Council of Australia, which represent the interests of coalmining giants, was contacted by Guardian Australia but declined to comment, as did the Australian Bankers Association, which speaks for nation’s biggest banks.
News Article | March 3, 2017
A wind farm big enough to power 240,000 homes will be built near Dalby by 2020, the Queensland government has decided. In state Parliament on Thursday, State Development Minister Anthony Lynham announced the environmental impact study for the $500 million Coopers Gap wind farm proposed by AGL Energy had been approved by the Co-ordinator-General. Start the conversation, or Read more at The Age.
News Article | March 29, 2016
by Giles Parkinson RWE’s Weisweiler lignite power station Germany in 2008 (photo Neuwleser) Reneweconomy.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. Merit order 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 centred around solar, storage, smart grids and electric vehicles. Strategic reprioritization “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 cent. 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. Implications 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 [i.e. for 1 tonne CO2 emisson allowance] 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 the 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. Editor’s Note This article was first published on Reneweconomy and is republished here with permission.