Demand response: Time to take the leap of faith?

Traditionally in the UK, electricity supply has involved generation at large power stations located around the country with high voltage transmission and lower voltage distribution networks to deliver the electricity to consumers. In order to maintain secure supplies, the system must be sized to meet peak demands, which occur for relatively limited periods over the course of a year. 

Demand for electricity is expected to increase, while aging coal, oil, gas and nuclear plants are rapidly approaching the end of their lifetimes, placing additional strain on the system. As countries increase their reliance on intermittent sources of energy like wind and solar power, this brings additional problems. 

Because wind is relatively unpredictable and wind power generation not dispatchable, the National Grid and local distribution network operators (DNOs) are looking to increase demand-side measures to balance supply-side issues. Demand response (DR) is a method of reducing peaks in demand, by encouraging reduced consumption during peak periods or shifting consumption to other times when the overall demand on the grid is lower. 

DR participants sign contracts to reduce the amount of electricity they draw from, and/or generate power for, the National Grid at certain times in the day in response to their instructions. Increasingly this is being widened to DNOs because of stress placed on these regional systems at peak times. By increasing DR activity, DNOs can prolong the life of their distribution equipment, i.e. substations. 

Distribution Use of System

The DUoS charge covers the cost of receiving electricity from the national transmission system and feeding it directly into homes and businesses through the regional distribution networks. These networks are operated by Distribution Network Operators (DNOs) such as Central Networks. The distribution networks include overhead lines and underground cables, as well as substations and transformers, which reduce the electricity’s voltage to safe levels for use in homes and businesses.

What is Demand Response?

There are four main types of DR contracts (see Table 1):

Interruptible load contracts. These help to ensure system reliability by allowing suppliers to suspend supplies to certain customers, typically following an outage of a generation or network asset. Such contracts are more common in the heavy industry sector, e.g. manufacturing, refining, mining etc., but contracts for commercial customers also exist. Short term operating reserve (STOR) agreements with National Grid are a type of interruptible load contract as they involve suppliers asking consumers to reduce consumption at short notice.

Reserve services. These services are required by National Grid to ensure security of supply in the event of unexpected demand increases or reduced generation. Reserve services can be either increased generation or demand reduction. Examples include fast reserve, fast start, demand management, STOR, and balancing mechanism (BM) start up.

Triad management. Triads are the three half-hour periods of highest national system peak demand during a year. They are not known in advance, but can be forecast as they typically occur during late afternoon / early evening on cold winter week days between November and February. Charges for using the transmission network are distributed between electricity suppliers based on consumption during these periods. The suppliers in turn pass these Triad charges on to their customers. Triad management involves reducing consumption for around two hours during expected peak periods in order to minimise these charges.

Distribution use of system (DUoS) charge management. DUoS charges are levied on consumers to cover the cost of using the distribution network. DUoS charges for half-hourly metered customers may be comprised of several elements, some of which can be reduced by changing when power is consumed.

Table 1: DSR measures and characteristics

In July, London-based low?carbon energy consultancy Element Energy published a report entitled Demand-Side Response in the Non-Domestic Sector on behalf of the UK Department of Energy and Climate Change. In the report, Element Energy estimated the technical potential for demand response across all sectors of non-domestic buildings in Great Britain at 1.5 GW-4.5 GW. By comparison, peak demand is 60 GW.

Peak demand in non-domestic buildings is around 17.5 GW and this occurs at around 11am on a winter week day. Element Energy found the greatest potential for the use of DR in the retail and commercial office sectors primarily by reducing loads from lighting, heating, ventilation and air conditioning (HVAC), hot water and refrigeration. 

Reduced lighting load was seen as the single biggest source of potential DR, as it accounts for 40% of annual electricity consumption. However, Element Energy found many energy managers and building owners are sceptical about the potential for reducing lighting in times of peak demand; their logic being that if lighting can be reduced in times of peak demand, it can be reduced at all times. Recognising this, Element Energy estimates the technical potential for DR excluding lighting at 0.6 GW-2 GW. 

How to do demand response

An increasingly common method of DR is STOR, which was launched by National Grid in 2007. By entering into STOR contracts, participants reduce their metered consumption from the grid at peak times (and therefore high prices). Participants can either simply reduce their load, or use back-up generators to make up the shortfall, i.e. peak lopping. They can also export power from on-site generators to the grid during agreed times.

There are two primary forms of payment for DR (see Table 2): availability and utilisation. Availability rewards participants for the amount of power and number of hours per day they can reduce or provide load. The second payment is for load utilised, i.e. power not used or power generated by on-site sources like diesel gensets.

Table 2: Annual revenues EDF Energy’s Smart Response per 1 MW installed

Larger DR participants often contract directly with the National Grid or DNOs to provide a relatively high capacity. The National Grid’s STOR programme requires a minimum generation or load reduction of 3 MW; the delivery of this generation/load reduction within no more than 240 minutes of receiving instructions from National Grid; and to provide the contracted load for at least 120 minutes when instructed; have a recovery period after provision of not more than 20 hours; and be able to provide STOR at least three times a week.

Clearly not all willing participants are able to supply this amount of reserve. However, commercial aggregation service providers such as EDF Energy, Flexitricity, KiWi Power (a full list of providers can be found on National Grid’s website) create a basket of participants who together comprise 3 MW or more collectively.

To avoid the complicated processes of bidding into the balancing mechanism market, the aggregator agrees the bidding strategy around what prices will be available should the client compete in a demand response activity, rather than the client having to deal directly with the National Grid. However, DR participants will need minute-by-minute data so that aggregators can understand how much energy their client is using at any point in time. 

Many non-residential users have only half-hourly meters, so aggregators install real-time metering systems for DR. Aggregators are keen to stress that the cost to their clients is minimal, so the metering equipment is installed at no charge to the DR participant.

Alastair Newens, business development manager of one such aggregator, KiWi Power says: “There is no cost at all to the consumer to participate in DR. We install the metering, controls and communication equipment at no cost to the client.”

Kiwi Power has developed a ‘software dashboard’ worth an estimated £10 000 which is given free to their clients. The system monitors and models power consumption, information which the National Grid needs to ensure DR can be deployed.

Plant can either be remotely turned down, or manually by the client. “If our clients need to reduce power consumption they will get a call from us and then typically they’ll have 20 minutes to achieve demand reduction,” says Newens. “We can do this remotely or we can communicate via phone call and/or email.”

How to deliver capacity 

Once satisfied that a client meets DR requirements, aggregators will then agree a strategy, perhaps to power down HVAC systems, or change set points of temperature within a cold store at peak periods. As aggregators take on the risk of non-performance, the onus is on them to ensure these strategies are up to scratch. 

The first thing to do, says Michael Capper, B2B Energy Services Manager at EDF Energy, is to understand how much energy a DR client’s buildings are using and where they are using it, be it lighting, HVAC, refrigeration or hot water. 

“We conduct a survey with our clients to ascertain where savings can be made with an honest and open discussion about what they can physically deliver,” he says. “A hospital, for example, may not want to turn down lighting for its patients. If a client has a large cold store, for example, can they switch off the load for a certain amount of time without the temperature rising to a certain level?” 

If a DR participant intends to feed power onto the grid, they may need to liaise with distribution companies to make sure they have the correct equipment, such as a G59 loss of mains protection relay, and the necessary certification. Capper says dealing with DNOs can be bothersome, but EDF works with clients through this process. 

Participants also need to assess their existing back-up power generation equipment, says Capper. “We need to understand the condition of their generators. Do they need replacing? Are they being used on a frequent basis? Is a maintenance regime in place? How quickly can the units ramp up when needed?

“This is a frequent problem, a lot of generators are only tested once, maybe twice a year, and often we find faults that need correcting. But if a client is utilising their generators on a frequent basis, DR can provide more security to buildings because we’re making sure the kit works.”

Newens says Kiwi Power typically asks its clients to run its generators 20-30 times a year for 40 minutes. This equates to roughly twice a common testing schedule of once a month for 30 minutes.

Potential barriers to DR

A recurring theme from potential clients is concern over comfort levels, that by entering into STOR contracts they will lose control over business-critical applications. “They say that they are not there to provide DR, they are in business to provide goods and services,” says Capper.

“We understand that and we make absolutely sure that DR has no impact on their core business. Particularly when there is load shedding involved we make sure any impact has been mitigated to the point where they are comfortable participating in demand response.”

Capper says clients often enter into an initial test phase to see the effect upon their business before applying DR to their entire estate. Aggregators also offer a flexible DR scheme whereby clients can opt out depending on their needs at certain periods.

“If they’ve got a restocking exercise or a big IT operation happening over a weekend, that will get preference over DR,” explains Capper. “So we work with our clients to prioritise and fitting DR into their operations, not the other way round.”

Barriers

Ian Walker, director of Element Energy, says his report into DR in non-residential buildings echoed these concerns. “There is a lot of fear of the unknown with DR, particularly for commercial offices which are multi-tenanted and have several potential stakeholders taking the decision to go for DR services.”

“We find that many organisations’ first port of call for demand response is HVAC, as this is not a business-critical application. Many are not yet comfortable with the technology or the service providers to let loose with more critical loads like refrigeration.”

One such company is the British supermarket chain Asda, owned by Wal-Mart. Louise Hall, Asda’s energy manager, is yet to be entirely convinced by DR. 

“At the moment we are conducting load shedding only for HVAC. We have parameters in place to stop store temperatures falling too low or rising too high, which in practice has proved difficult to implement STOR contracts because we can’t guarantee load reduction.

“One of the issues we found when looking at this recently was maintaining the level of energy reduction. Once you’ve done your initial reduction you need to make sure it is maintained. Being a supermarket, we may need to use a bakery oven, for example. It has to come on; we can’t just switch it off. 

“Our primary focus is that DR is non-customer impacting, so whatever we do the customer doesn’t know that we are doing it, which is why we have avoided demand response for lighting. So what we’re doing at the moment is purely doing HVAC load shedding through our building management controls to avoid peak DUoS costs. The next stage for us is to do a generator trial through a STOR programme.”

Financial Rewards

Hall says the financial incentives on offer to Asda are limited at present. “Our finance teams like clarity over payback terms and times. Because the financial incentives on offer are based around bid prices, which are different at different times of year and it’s not guaranteed that you get those prices, it’s quite difficult to prove the business case and the exact payback period.”

Element Energy’s Walker found a similar response in his report. “A lot of the organisations we spoke to didn’t feel DR contracts were sufficiently attractive to take on the risk of possible loss of service, particularly for the more high profile office blocks where presumably rents are high. The revenues accruing from demand response just didn’t seem to be enticing enough to take any risk on service levels.”

While most people would be very grateful for receiving an additional £50 000 a year for doing nothing, for many large businesses this is not perhaps such a huge sum. And for a small business using aggregation service providers, the returns would be a fraction of these relatively low figures. Is it worth the effort?

“Some of our clients may have only 1 MW or less on one site but they may have 200-300 sites in total,” says Capper. “Also, these figures are based on the current market and one must always consider what might happen to the market in the future. Given the number of power plants due offline in the coming years, where’s the market is going to be three to five years?”