Demand response, the opportunity for energy consumers to switch to supply

The potential for electricity users to ease stress on the grid by turning down consumption during peak events is seen as an easy solution to our energy woes, writes Jeremy Chunn.

When demand for electricity outstrips supply, things can snap. That’s why peaking generators are built … only to stand idle until the handful of days they may be called upon as temperatures soar and air-conditioners are dialled to chilling lows.

There is an easier and cheaper way to dispatch emergency supply, however, by simply turning down demand.

Unleashing this extra energy by urging a roll of participants to lower their usage is called demand response, and the Australian Renewable Energy Agency has teamed with the Australian Energy Market Operator on a $37.5 million three-year pilot program to find 160MW of on-call power before next summer.

It’s good news to Chris Dunstan, research director at the Institute of Sustainable Futures, who says demand management is the perfect complement to renewable energy. Although a simple agreement to cut demand is in many cases cheaper, quicker and cleaner than building new transmission or utility-scale storage, “it is sadly too often overlooked.”

It may turn out to be a hard task, however, because building “virtual power stations” using demand response and operating them in a wholesale market is not at all trivial. It’s made harder in Australia’s largest electricity network because the National Electricity Market is an energy-only market, where there are limited options to be paid for making demand response available to the grid. In the NEM, retailers are “very much in control” of the types of pricing structures their customers are presented with, a source told EcoGeneration.

Ready reliability

Demand response can take different forms, including foregoing planned consumption, shifting consumption outside a time window or switching to standby generation. Unlike other forms of demand management such as load shifting or time-of-use pricing, demand response is dispatchable by the grid operator. Like a power station, it can receive a dispatch signal and deliver its capability.

The most common reason for demand response is to provide reliability, where a grid operator will create a market framework for demand response to be dispatched for example on the hottest days of summer, when grid demand is at its peak. In that instance, demand response serves the role of an emergency lever the grid operator can pull when they’re running out of options on the supply side. When called upon, customers who have opted in reduce their demand in return for compensation.

It is impossible to do that in the NEM today, but the ARENA-AEMO funding will be channelled towards getting that mechanism going. In its May announcement about the funding ARENA said participants called upon by AEMO to reduce their demand from the grid would receive a pre-agreed dispatch payment through AEMO’s Short-Notice Reliability and Emergency Reserve Trader mechanism.

Track record

Demand response is not a technology that is new or needs to be proven globally. There are dozens of wholesale markets around the world where it is used successfully. Global demand response giant EnerNOC works with commercial and industrial energy users with large sophisticated loads. Working that way, 1MW of demand response can be apportioned to one manufacturing facility instead of knocking on the doors of 40,000 residential customers.

Demand response aggregators who have built a peaking resource for the market will earn the prevailing wholesale rate for those services.

The idea is that an aggregator will make a firm commitment to the grid operator to deliver a certain amount of capacity at a certain time, with financial penalties or downside if they come up short. There is very little tolerance for under delivery, EcoGeneration was told.

In the United States, grid operator PJM has a large sophisticated market mechanism to supply demand response, which accounts for about 6-7% of all capacity in its network. This means that each year 93% of capacity is met by generators and 7% by demand response.

In Australia, the demand response market is very quiet. But it won’t be for long.

At work and at home

Early this year Mojo Power trialled the notion of demand response on a volunteer sample of 500 customers. The retailer, which has a client base of residential customers in NSW and Queensland, chose a day in February where very high temperatures had brought a forecast of energy curtailments. “We sent a text message to 500 of our smart-metered customers in NSW, offering an incentive to those who would turn off power later in the day,” says Mojo Power CEO and co-founder James Myatt. “Forty percent of people responded within about 30 minutes, saying they were willing to participate.”

Mojo Power CEO and co-founder James Myatt.
Photo by Damian Shaw
www.thephotopitch.com

At 4pm the retailer sent the request for the respondents to switch off appliances and demand was cut “quite significantly”, Myatt says. “We didn’t know until we got the meter data what the effect had been but … the top 20 customers basically reduced demand to zero.”

The trial had shown the potential for a voluntary product, but mystery remains about what would happen in the event of consecutive days of requests to customers to shut down. None of the smart meters were fitted with weather predicting capabilities. “At this stage it’s not automated,” Myatt says. “It’s more on a forecast market. We know in advance reasonably confidently whether the price is going to be high.”

To Mojo, the program represented a benefit per customer of about $390 over two hours. To customers, the cost of two hours of relative discomfort was offset by a $25 bill credit.

If further trials over consecutive days test customers’ tolerance, a more “dynamic” offset (that is, an offer of more money) might attract greater participation, Myatt says. “We’re looking at different concepts,” he says. “We wanted to see what sort of response we got on an ad hoc basis before we structured it.”

At Mojo HQ the trial was deemed a success; the response rate was encouraging and customers didn’t prevaricate. “And we got positive feedback,” says Myatt. “[Many said] it was the first time their energy retailer had engaged with them to allow them to profit from the wholesale market.”

Mojo is involved in the A-Lab demand response scheme but admits a residential demand management control program could be a way off. There is physical kit to be installed, for a start. But there is potential, Myatt says, for voluntary demand product. If it gets scale, yes it can bid into a demand management product. If it doesn’t, it’s still valuable to a retailer and keeps customers happy.

Competing incentives

Chris Dunstan, research director at the Institute of Sustainable Futures within the University of Technology Sydney, says it’s about time the option of managing demand was taken seriously. Dunstan’s research team released its Demand Management Incentives Review in June, well-timed to ride the opportunity presented by AEMO chief Audrey Zibelman’s vocal intentions to explore the strategy. “Demand management has been overlooked in Australia for a very long time,” Dunstan says. “It could have solved a lot of problems over many years.”

Dunstan regards demand response as fitting into the broader category demand management and explains that when the NEM was designed in the early 1990s it was intended that demand management would have a significant role to play, but the supply side took priority and demand management was “left as an afterthought”.

Demand management in networks he says accounts for about 40% of the value chain, with complex rules via the Australia Energy Regulator providing competing incentives. Dunstan’s research, commissioned by ARENA, has isolated the cause. “Once you take into account all of the relevant incentives created by the regulatory structure there is actually a bias against demand management and in favour of network capital expenditure,” he says.

The report found that if Australia had as much demand management as the average four states in the US, we would have about 3,000MW of demand management on call. If one were to offset the withdrawal of 1,600MW, equivalent to Hazelwood’s closure, with a 3,000MW reduction in demand at peak times it would have significant impact on reducing prices, he says.

“Similarly, if we had used demand management more thoroughly in the period between 2007 and 2014, when we saw electricity prices double mainly because of investment in networks, then we could have avoided a significant chunk of the tens of billions spent on network infrastructure.”

The cost to productivity of cutting load at peak times would be more than offset, he says. “If it’s not an attractive business proposition to customers then there is no obligation on them to reduce demand,” he says. At the same time, prices for all other consumers are suppressed. “It’s a win-win.”

Plan ahead

Energy Queensland’s demand management strategy includes managing the potential of storage and use of load control by offering appropriate incentives for customers, says executive general manager of strategy, portfolio and innovation Craig Chambers.

“Storage is going to be part of the future and Energy Queensland’s distribution businesses – Ergon Energy and Energex – have recognised this by streamlining the processes and requirements for connections and communicating with customers the importance of notifying their distributor that a storage system has been connected,” Chambers says.

It’s all part of Energy Queensland’s plan to enhance its services to owners of distributed energy resources, including the management of energy storage (including electric vehicles) and behind-the-meter hubs and devices, Chambers says.