This article first appeared in the November/December 2013 issue of Intelligent Utility magazine
By now most will be aware of the dreaded utility “declining demand death spiral”: As solar PV grows, utilities’ demand drops. Utilities respond by raising prices and/or network charges—either for solar or non-solar customers—further incentivizing solar (and battery storage), thus further reducing demand.
Few places are more likely to experience the death spiral than Australia—a vast, sun-drenched nation with huge distances between urban and rural populations.
The highly-populated East Coast National Energy Network—connecting Queensland, New South Wales, ACT (Australian Capital Territory), Victoria, South Australia and Tasmania—currently has 3 GW of solar PV out of 35 GW peak demand. Yet, this relatively small proportion is having a material impact on utilities.
Queensland regulated utility Ergon Electricity, which operates 160,000 km of power lines in a territory of 1.7 million square kilometres with only 700,000 customers, is shedding hundreds of jobs in an effort to stay competitive with solar suppliers who do not have a distribution grid to support. Utilities are fighting back with an increasing rejection of rooftop applications due to network constraints, but the rising tide of solar will only get harder to stem as solar costs fall.
Distribution network service providers (NSPs) are keen to introduce a residential capacity charge for solar power, effectively a tax on the sun, to mitigate the death spiral. But this, of course, may also have the opposite effect. In Australian states where rooftop solar PV power generation in winter is adequate (such as Victoria, South Australia and Tasmania), consumers may begin to desert the grid.
It is with this in mind that CSIRO (Commonwealth Scientific and Industrial Research Organisation) is studying the likely impact of a potential death spiral. CSIRO is leading a report by the Future Grid Forum (FGF) —due to be published by the end of 2013—with input from input from virtually every Australian generator, transmission and distribution network operator, plus regulators, consumer groups and regional/national government.
“By 2030 we fully expect to have more solar power generation during the daytime than the grid can deal with,” said Dr. John Ward, CSIRO research leader. “Australian peak demand occurs during the middle of the day. But if the take-up of solar increases as expected, this will shift to early evening, and the need for load management during the early evening becomes considerably more important.
“The nature of the ‘death spiral’ is that it leaves those not in a position to go off-grid in a very bad place. Furthermore, we may have to run a 100 percent redundancy system with large amounts of spinning reserve, as well as paying to deal with voltage control problems at the distribution end.”
The FGF has been discussing in detail how the industry can move to a more cost-effective solution. “The high penetration of solar power will require either balancing prices to rise significantly or a fundamental change in the market and we have been discussing this at length,” said Ward.
One way could be battery storage. Australia’s solar feed-in tariff is roughly equivalent to the wholesale price, and consumers can already start thinking about using storage to manage the price differential between peak (A$0.525/KWh) and off-peak (A$0.137/KWh) regulated prices.
Ward added, “Power suppliers are certainly thinking about selling systems rather than merely electrons, but it’s murky territory having a generator or NSP having involvement with equipment on the customer-side of the meter. It’s not quite clear how this will play out, but the NSPs in particular are looking at this from the perspective of network upgrade costs. Is there a more cost-effective solution which involves storage on the customer’s site and how they make that work from a regulatory point of view?”
NSPs have been exploring exactly this in trials. The Smart Grid Smart City project by Ausgrid, which operates the distribution network in the Sydney, Central Coast, Hunter Region and Newcastle areas of New South Wales, deployed both battery storage systems and fuel cells outside of the usual regulatory environment to answer questions about social acceptance of the technology.
CSIRO is also working on a number of research projects to better understand the relationship between solar power, storage and the grid. The projects are concentrated in remote communities, where power prices are highest and power quality is lowest. One such project, called Plug and Play (PnP), is motivated by improving understanding of solar generation forecasts in order to reduce spinning reserve, i.e. diesel generators, or replace it with energy storage.
CSIRO is undertaking the A$2.9m ($2.8m) project with ABB Australia and the U.S. National Renewable Energy Laboratory (NREL). The first phase of the project will involve the development of the technology; the second phase will see pilot systems set up in both the United States and Australia.
Users will be able to “plug” in the generation sources and the system will “play,” i.e. work out which source to use based on programmable parameters, such as maximising power availability, minimising diesel usage or lowering maintenance costs. In essence, PnP will make the decision when to schedule the diesel generator, when to use solar energy and when to charge the batteries.
Dr. Ward says forecasting is crucial to the process. “The better we can improve load and generation forecasts the better we can improve the energy management system, i.e. the batteries,” he said.
Ward adds PnP will be a useful tool for microgrid project developers who want an out-of-the-box solution rather than custom-made hardware and software for each installation.
“As the electricity grid evolves to have more interplay beteen consumer demand and resource availability, there’ll be a role for PnP-type systems to become mainstream in every part of the electricity grid,” he noted.