Storage to Solve an “Energy Crisis”?
The Riverland project is located about 125km north east of Adelaide, in South Australia.
The state of South Australia has excellent solar resource, around the 2000 kWh/m2/yr mark in the project location region and up to around 2300 kWh/m2/yr in the northernmost part of the state. It is also a state that has encountered significant problems with its electricity supply, particularly during the summer of 2016/2017, as described later in this document.
Riverland is just of one project within a pipeline of solar PV farms with battery storage, under construction or proposed by Lyon Group. Their total pipeline adds up to more than 1.7GW of grid-connected PV and 1GW of battery storage by 2020.
Lyon Group is backed by Japanese giant Mitsubishi and Blackstone (via US hedge fund Magnetar Capital).
In November 2017, they announced their intention to sell off three of their in-development projects by the end of the year, including Riverland. A short-list of bidders was already being considered. Selling off these projects was designed to help funding the continued pipeline: a classic pure-development play, rather than a develop-build-operate model.
The project location:
The Project by numbers
The solar farm will have a maximum capacity of 330 MW, with maximum active power injection through two grid lines: one 160MVA and one 110MVA. These lines already run through the chosen site, which is just 2km from a grid substation.
There will be 3.4 million panels, which will be on trackers. The project will include a total of 1847 km of cabling (DC plus AC) and cover 600 hectares.
The estimated investment is (AUS) $700m, of which there will be $100m in local content – covering site preparation, access roads, accommodation, tracker assembly and panel install. The project construction is expected to employ 270 workers. The highest workforce requirement is during the installation of the PV panels, which covers a three-month period between months seven and nine of the construction schedule.
The battery storage system will be 100MW power capacity, with a likely energy capacity of 400 MWh (at the time of writing, the exact power/energy ratio remained “dependent on configuration”). It will include 1.1m individual batteries.
The storage cost is expected to be somewhere between $250 and $300m; making the whole project a potentially $950m – $1bn investment.
The project is 100% equity financed.
As of March 2017, land had been secured, technology and other commercial arrangements were “in place” and development consultation and approvals “commenced”. Lyon’s project partners at this stage included US-based energy giant AES Energy Storage (a utility-scale energy storage provider) and the EPC contractor Downer.
The network capacity analysis and grid connection process was described as “already well advanced”. However even with an apparent proximity to grid lines, reports in November 2017 suggested that securing the grid connection agreement with the local transmission operator was taking longer than initially hoped.
Community liaison sessions started at the end of May 2017. Construction was originally planned to start in September 2017, with a target of commercial operation by first quarter of 2018. However delays (including those mentioned above, with grid connection) meant that by November 2017 construction was behind schedule and still hadn’t broken ground. (Commercial operation too, will therefore be later than originally planned).
According to quotes from Lyon Group’s CEO, the solar power generation will qualify for renewable energy subsidies of AU$84/MWh, additional to the wholesale market price.
For comparison, the Australian Energy Regulator states the annual volume weighted average spot price in South Australia in 2015/2016 as $67 per MWh. In April 2017, as I write, yesterday’s spot prices varied widely and to high peak values, moving between 20 and 200 $/MWh at 2am and 6pm respectively!
The rationale for this PV-plus-storage project is stated as to “deliver reliable, flexible power to meet South Australia’s summer peak.” In other words, it is looking to take advantage of those high peak prices.
In June 2017, Lyon Group launched what was believed to be the world’s first utility-scale battery storage market services tender. They hoped to attract a range of players, from electricity retailers and generators to large electricity users, entering into commercial contracts to deliver multiple services on various scales, from the same battery system.
Their tender announcement listed a range of potential services from energy price arbitrage, load shifting and renewable energy ramp control, to frequency control, system restart services and firming capacity. It is believed to be the first time that the final engineering design of a storage project (in particular the optimal time duration of storage: its MWh capacity) had been so strongly linked to market requirements; to be revealed by the outcome of the tender.
By November 2017, development approvals and offers to connect were described as “either granted or imminent“, including an agreement with the Australian Electricity Market Operator (AEMO) which expected to be “rubber-stamped” by February 2018. With the project fully ready to go ahead, but not yet in construction, Riverland was one of three Lyon Group solar-plus-storage projects (also described as “dispatchable renewable” projects) offered for sale. The aim was to complete the sale by the end of 2017.
In addition to everyday peaks, South Australia experiences rare-but-large extreme peak demand events. On some days, the demand for electricity can be more than double the average demand on a typical day. This only occurs a few times each year, happening on extreme (hot) summer days and driven by increased use of air conditioners in homes.
Early in 2017, South Australia was widely considered to be in an “energy crisis”. That diagnosis followed a state-wide power outage event that occurred on 28th September 2016 (a “black system” event). Then a heatwave that occurred on February 8th 2017 led to the load-shedding of 90,000 South Australians.
Power outages are managed across the national electricity grid by the Australian Energy Market Operator (AEMO), and locally in consultation with the Government of South Australia, ElectraNet (the TNO – transmission network operator) and SA Power Networks (the DNO – distribution network operator).
The AEMO reported that the black system event was caused by a sequence of events, briefly:
- Two tornadoes simultaneously damaged two different 275kV transmission lines, causing them to ‘trip’ and resulting in multiple voltage dips on the grid within a two-minute period.
- This number of voltage dips caused a protection feature to be activated on eight wind farms, leading to a generation reduction of 456 MW over a period of just seven seconds.
- To offset this reduction in windfarm output, a big increase in imported power flowing through an interstate interconnector (the Heywood Interconnector) was needed. But the rapid increase in flow activated another protection scheme; this one tripping the Interconnector offline. As a result, South Australia became ‘islanded’, separated from the National Electricity Market.
- The remaining generation in the islanded state system was insufficient to meet the connected demand and so the frequency of the system could not be maintained – leading to the full system blackout.
The load-shedding event in February 2017 occurred when Adelaide endured a maximum temperature of over 42 degrees. Some inland locations saw readings exceeding 46 degrees. The resulting demand level corresponded to AEMO’s “P10” maximum half hourly demand forecast for South Australia. That means a forecast expected to be exceeded only one year in ten.
During this event, prices spiked to $13,000-$14,000/MWh for over 2 hours (which included the load-shedding period).
Some of the gap between local supply and demand was met from the two interconnectors linking SA to Victoria and the rest of the NEM. Rolling controlled load shedding over a period of about 1 hour was used as the last option to keep the system supply and demand in balanced.
Storage to the rescue?
Providing additional generation and/or grid infrastructure to supply large quantities of electricity for very short periods to meet peak demand in extreme circumstances is costly. These are costs which ultimately end up on customers’ bills. This volatility in pricing, along with the susceptibility of the grid to failure in certain circumstances, are both symptoms of a system that lacks flexibility.
In South Australia, renewable generators now represent more than 43% of local installed capacity (2,297MW: 70% wind and the remainder largely rooftop solar). Gas and liquid-fuelled thermal generators provide the rest of the share.
Adding to the challenge, Australia is encountering a gas supply shortage. A recent report by the AEMO predicted that declining gas production could lead to major electricity deficits as soon as summer 2018. Climate commitments and an old fleet – built in the 70s and 80s – means an increasing number of Australia’s coal power plants are also due or likely to close. In other words, dispatchable generating capacity threatens to shrink (both in South Australia and neighbouring states).
While Australia’s excellent solar resource and the plummeting costs of PV technology point to one way to fill some of that energy gap, PV is not dispatchable. Clearly storage, whether located at solar farms or elsewhere in the grid, could provide the flexibility that solar PV alone lacks.
Thus, following the summer energy crisis in South Australia, in March 2017 Tesla’s vice president for energy products (Lyndon Rive) created much press coverage by announcing that he would commit to installing 100 to 300 MWh of batteries in Australia within 100 days. When asked how serious Rive’s guarantee was, Tesla boss Elon Musk – via twitter – went further: “Tesla will get the system installed and working 100 days from contract signature or it is free. That serious enough for you?”
Though not taking up this offer directly, the South Australian government did launch a tender for 100MW of battery storage, with the aim of having a battery in place by December 2017. The tender generated a huge response from interested parties, with more than 90 proposals submitted in a first fact-finding round. The eventual winner was Tesla, whose “big battery” project is profiled in a separate case study write-up: here.
According to Lyon Group, the Riverside project will go ahead regardless of the outcome of the South Australian government’s large-scale battery storage tender. The latter could however influence the final storage configuration at Riverside. That would be in terms of setting it up to achieve the best (most economic) balance between grid optimisation and the capture of trading revenues.
First of many? Lyon Group have a huge project pipeline, of which Riverland is just one (source: Lyon Group)
New Market Rules?
One potential and important policy change ahead would be the acceptance of a proposed change to the current 30-minute settlement rule in favour of a 5-minute settlement.
While this might seem an arcane detail of the energy market, it has big implications for the future of the industry, not least for storage. That’s because a 5-minute rule would encourage fast-acting technology such as battery storage and demand response (and hence create the conditions to attract more investment). The 5-minute rule has the backing of the Australian Energy Market Operator (AEMO) and the Australian Energy Regulator.
However the rule change will almost certainly be opposed by owners of large generators, particularly those with existing generating assets that cannot respond quickly to demand and supply changes and wholesale market price signals. Indeed incumbent fossil fuel generators have even been accused by some of using the 30-minute settlement to manipulate the markets; by withdrawing capacity to force up prices at certain periods, then flooding the market with suddenly available capacity to cash in on the windfalls.
First published: April 2017
Last updated: November 2017