A closer look at Frequency Response

System frequency is a continuously changing variable determined and controlled by theSystem frequency second-by-second (real time) balance between system demand and total generation/supply. Though supply and demand is a continuously changing variable, National Grid has an obligation to control to +/-1% the nominal system frequency of 50.00 Hz. How does the grid maintain this delicate balance? While there are mandatory requirements for all large generators connected to the UK transmission network to grant automatic change, there are also schemes including Firm Frequency Response (FFR) and Frequency Control Demand Management (FCDM).

FFR vs. FCDM

FFR is the firm provision of either a dynamic or non-dynamic response provided by participants outside the mandatory balancing mechanism. Recall that dynamic response is a service where energy constantly changes in line with system frequency, while non-dynamic response, or static response, is triggered when the frequency deviates from a pre-set level. FFR allows participants to provide a service whereby they reduce demand or increase generation as instructed by National Grid. During utilisation, National Grid would instruct the provider to set its asset (eg, pumping equipment or UPS) into frequency sensitive mode via electronic relay. This would then automatically change the unit’s output in response to the system frequency.

FCDM is another commercial frequency response service provided through automatically disrupting electricity demand when the frequency drops. This service specifically aims to prevent the fall in system frequency below the statutory limit of 49.5Hz, and generally, frequency does not commonly fall below 49.70Hz unless there is an unplanned generation loss or demand increase on the system. The FCDM service allows the provision of frequency response through the interruption of customers that use large amounts of electricity via low frequency relay which will disconnect a pre-agreed level of demand. As demand falls, the frequency should increase.

A summary of the differences between FFR and FCDM is included in the below table.

FFR FCDM
Key characteristics:
  • Balancing Mechanism – not mandatory
  • Dynamic or non-dynamic
  • Balancing Mechanism – not mandatory
  • Non-dynamic
What is the minimum threshold for participation?
  • Deliver minimum 10MW Response Energy
  • Deliver minimum 3MW, which may be achieved through aggregation
  • Provide the service within 2 seconds of instruction
  • Deliver for minimum 30 minutes
What equipment can be used? Diesel rotary uninterruptible power supply (DRUPS).For generation, DRUPS systems, stand-by generators and other distributed generators. HVAC system components.
What is the compensation? FFR has a four-part payment structure. However, participants do not have to tender in all these payments:

  1. Availability Fee (£/hr) – the number of hours of availability from a provider
  2. Utilisation fees –
    Window Initiation Fee (£/window) – for each FFR window that the provider has been instructed under.
    Nomination Fee (£/hr) – for each hour utilised
  3. Tendered Window Revision fee (£/hr) – National Grid notifies providers of window nominations in advance and, if the provider allows, this payment is payable if National Grid subsequently revises this nomination.
  4. Response Energy Fee (£/MWh) – based upon the actual response energy provided in the nominated window
Participants are paid only on availability in £/MWh and this is calculated based on the aggregated metered MWh of demand during the accepted availability periods.
How do I participate? FFR is procured through a monthly tender for one or multiple months. Due to the bespoke nature of service provision, this service is provided through bilateral negotiations.
What are the technical Requirements? A FFR provider must:

  • Have suitable operational metering
  • Pass the FFR Pre-Qualification Assessment
  • Operate at their tendered level of demand/generation when instructed
  • Have the capability to operate (when instructed) in a Frequency Sensitive Mode for dynamic response or change their MW level via automatic relay for non-dynamic response
  • Communicate via an Automatic Logging Device
  • Where a single FFR unit comprises of two or more sites located at the same premises, be able to instruct and receive via a single point of contact and control.
A FCDM provider must:

  • Have suitable operational metering
  • Provide output signal into National Grid’s monitoring equipment

Frequency response may be a lucrative option for businesses that are able to interrupt their demand instantaneously for short periods of time, but a major hurdle to participation has been the minimum threshold for direct enrolment with the National Grid. Demand response aggregators such as KiWi Power, however, can enable participation.

Frequency Response: The Grid’s First Defence

What is grid frequency and why is it important?

Image courtesy of Dynamic Demand

Image courtesy of Dynamic Demand

System frequency is a continuously changing variable that is determined and controlled by the second-by-second (real time) balance between system demand and total generation/supply. If demand is greater than generation, the frequency falls while if generation is greater than demand, the frequency rises. National Grid must ensure that sufficient generation and demand is held in automatic readiness to manage all circumstances that might result in frequency variations. National Grid must control the frequency to be plus or minus 1% of the nominal system frequency of 50.00 Hz. A sudden drop in grid frequency is a crucial indicator that the grid is under stress, and National Grid’s control room must take immediate action.

How does National Grid keep system frequency in balance?

Frequency response is designed to cope with the loss of two 660 MW sets in quick succession. There is about 2.5 GW of such frequency service loads available in the UK to cover a peak demand of about 60 GW. National Grid’s control centre keeps the system in balance and has a team of specialist system operators that forecast the demand for electricity by taking into consideration factors such as the weather, the time of day, historical data and also if there are likely to be any ‘TV pickups’ caused by popular television programmes or major televised sporting events such as the Olympics or World Cup – something that is unique to the UK.  National Grid will know in advance that when the demand for electricity increases at these particular moments, supply will have to be increased in order to match and keep the system frequency balanced. National Grid will do this by using generators including renewables such as wind to come online or offline and increase or decrease their output, depending on demand. National Grid pays for generation to come on or off the network in advance, or procures from the balancing mechanism a few hours before the energy is needed.

What is frequency response?

Frequency response describes another National Grid balancing requirement, where response is immediately required in a matter of seconds to a change in overall grid frequency. Frequency response can come in two forms: Dynamic response and Non-dynamic response. Dynamic response is a service that is provided constantly to help manage the normal second-to-second changes on the system. Non-dynamic response is only used when there is a defined frequency deviation. National Grid uses the following three balancing services to control system frequency:

Mandatory Frequency Response- MFR is an automatic change in active power output in response to a frequency change. According to the Grid Code, all large generators that are connected to the transmission network in the UK under the Grid Code are required to have the capability to provide Mandatory Frequency Response to the National Grid.

Firm Frequency Response -FFR is the firm provision of either a dynamic or non-dynamic responses, which can be provided by participants outside of the balancing mechanism. Unlike Mandatory Frequency Response, FFR is a commercial service that can be provided by parties outside of the Balancing Mechanism. A contractual agreement regarding utilisation payment for providing the service is made in advance of service provision. FFR is open to Balancing Mechanism Unit (BMU) and non-BMU providers, demand and generation, existing Mandatory Response providers and new providers alike.

Frequency Control by Demand Management- FCDM is another commercial frequency response service, provided through automatically disrupting electricity demand when the frequency drops. The electricity demand is automatically interrupted when the system frequency transgresses the low frequency relay setting on site. The customers who provide the service are prepared for their demands to be interrupted for up to 30 minutes, where statistically interruptions are likely to occur between approximately ten to thirty times per year.

While MFR is only open to large grid-connected generation, FFR and FCDM may be lucrative options for many businesses that are able to interrupt their demand instantaneously for short periods of time. While the minimum threshold for participation is often prohibitive for businesses to participate with National Grid directly, demand response aggregators, such as KiWi Power, can enable participation.

Frequency Balancing: The Future Challenge

With more renewable generation coming online and traditional (baseload) generation retiring, balancing grid frequency is becoming increasingly challenging for the National Grid.

Traditional power plants (like coal and gas) are increasingly coming off the system and are being replaced by asynchronous plants like wind and other renewables, which makes balancing grid frequency even more challenging for the system operator. If it is a particularly windy day and an area is receiving generation from wind power, frequency will change at a faster rate, which consequently means more rapid frequency control capability is required. The opposite can be equally problematic: the newly installed and planned renewable distributed generation can cause frequency to fall at a faster rate if the sun stops shining or the wind stops blowing on a particular day.

Measuring the Rate of Change of Frequency (RoCoF) detects a loss of mains condition which occurs when a distributed generator stops generating electricity supply in a network area that is already experiencing generation issues. National Grid, along with electricity suppliers and distribution networks, are reviewing the future of RoCoF and its suitability with new forms of distributed generation being connected to the grid. Because arresting the RoCoF is of vital importance to the National Grid, new balancing services are being considered along with a number of changes to existing frequency response arrangements to ensure that the National Grid has the right tools to balance the grid.

Distribution Use of System (DUoS)

What is DUoS? Power station

Distribution Use of Systems charges (DUoS) is a time of use tariff similar to triads. However, DUoS happens on a daily basis and is added onto the monthly electricity bill. It is the charge for receiving electricity from the national transmission system and transferring it to the distribution level to be used in homes and businesses. Distribution Network Operators (DNOs) charge energy supply companies, such as British Gas, E.ON, and others, who then pass these charges onto electricity bills to cover the costs of installing, operating and maintaining the network.  DUoS can account for up to 12% of the charges on an electricity bill for half-hour meter industrial and commercial customers.

Half-hourly DUoS charges are made up of four different charges:

  • Capacity charge – Also known as the availability charge, this is a fixed daily charge that relates to the Maximum Import Capacity (MIC). MIC is the maximum demand of electricity a DNO has agreed to supply to a particular site.
  • Reactive power charges – These are charges placed on certain high load, equipment such as air conditioning units, which lead to increased power flows on the network.
  • Fixed charge – Regardless of how much electricity is actually consumed at a site, the electricity supplier still charges a fixed daily amount as part of the DUoS charges for maintenance of the network.
  • Unit charges – These are charges associated with each unit of electricity used, representing the bill payer’s actual use of the distribution network.

In April 2013, DUoS charges increased between 5% and 24%, which has added 0.06p/kWh to 0.43kWh to the unit charge.

What drives DUoS charges?

There are a number of drivers for DUoS charges, including time of day and geography. DUoS charges, in particular unit charges, can vary in price depending on when the electricity is used. There are three different rates: red, amber and green. Red is for peak periods such as weekday afternoons after 4pm, amber covers the rest of the daytime whilst green includes nights and weekends.

This table from Hudson Energy shows the different peak, mid peak and off peak electricity consumption hours for each of the DNOs. So for those time periods which fall under red, electricity consumption will be at its most expensive for customers. DUoS charges also vary in different regions. Just like triads, DUoS charges will be highest where the demand for electricity is high and costs of upgrading the distribution network are high, such as London, and lowest in places like Scotland.

DUoS charges are then calculated on a variety of factors.  These include:

  • Type of site e.g. HH (Half Hourly metered)
  • Agreed Export/Import Capacity (in kVA)
  • Voltage Level: High Voltage (HV) or Low Voltage (LV)
  • Line Loss Factor Class

These inputs are determined by the DNO to whose network the electricity is connected.

Managing DUoS Charges

Customers can save thousands of pounds just on unit charges alone which can make a significant difference on a yearly basis. There are several ways customers can reduce the amount of DUoS charges. By using electricity less during the red bands which is typically between 16:00 and 19:00 on weekdays, customers may be able to lower their DUoS charges to an extent, as charges are highest during this peak time band.

Businesses can also reduce their DUoS charges by installing power factor correcting equipment such as capacitors. This lessens the usage of reactive power and less electricity is lost therefore lowers DUoS charges. Another way in which businesses can reduce their DUoS charges is by making sure the site has the maximum import capacity that is actually necessary. For example, if the sites maximum import capacity is 400kVA and the site only uses 100kVA, then by lowering the maximum import capacity the company can save money because regardless of usage, they will get charged for the MIC in place.

With DUoS charges increasing yearly, businesses are becoming increasingly interested in finding ways to lower these charges and thereby lower their energy bills.

Image: EDW Technology

Image: EDW Technology

Flexible Approaches for Low Carbon Optimised Networks (FALCON)

Western Power DistributionWEST2219 Subbrands_concepts_B

Western Power Distribution (WPD) is the electricity distribution network operator (DNO) for the Midlands, South West and South Wales that currently delivers electricity to over 7.8 million people. It is the trading entity for four electricity distribution companies – WPD South West, WPD South Wales and WPD Midlands (formerly East Midlands & West Midlands). Each company acts as the DNO for its region but combined, this makes WPD the largest electricity distribution network in the UK. The network covers a 55,500 km2 area and consists of 185,000 substations.

WPD has received significant funding from Ofgem’s Low Carbon Network Fund (LCNF) to trial innovative low-carbon technologies as well as new commercial arrangements on its network:

▪   The Lincolnshire Low Carbon Hub aims to increase the amount of renewable energy that can be connected to the distribution network in the local area through wind farms and biomass power plants.

▪   Low Voltage Templates project encourages the use of domestic solar PV, heat pumps and the improvement of insulation around the house.

▪   Buildings, Renewables and Integrated Storage with Tariffs to Overcome network Limitations (BRISTOL) is looking for viable solutions to lower the stress low carbon technologies are bringing to the low-voltage distribution network.

▪   FlexDGrid: Advanced Fault Level Management in Birmingham is trialling a number of ways to overcome faults caused by the connection of low-carbon technology to electricity networks.

Of its Low Carbon Network Fund projects, WPD’s Flexible Approaches for Low Carbon Optimised Networks (FALCON) is the only one to incorporate demand response trials to date.

The FALCON project

The FALCON project began in 2012 and will operate for another two years. Awarded £13m from the LCNF, the programme aims to control the distribution of electricity to increase capacity on the 11kV network around the Milton Keynes area.  FALCON will test six different alternatives to coping with electricity demand across 200 substations, four of which are based around engineering approaches, with the remaining two approaches related to commercial techniques.

Engineering approaches:

▪   Dynamic calculation and utilisation of 11kV asset ratings to free up unused capacity

▪   Automated load transfer between 11kV feeders within primary substations to increase available capacity

▪   Creation of an interconnected meshed 11kV network in suburban and rural areas in order to maximise capacity

▪   Implementation of new battery technologies

Commercial approaches or demand response:

▪   Control of distributed generation to increase capacity on the 11kV network using new commercial techniques

▪   Control of customer demand to increase capacity on the 11kV network using new commercial techniques

The commercial approaches test different types of consumer responses to incentives to reduce their electricity consumption. Demand Response refers to when a company cuts back on its consumption to avoid peak time charges, or utilises embedded generation, which then awards participants for cutting back their consumption in response to a signal from WPD’s control centre.

These six approaches will allow WPD to assess the best ways to manage change in network demand that is expected to arise from increased usage of low carbon technologies. During these trials, the results will be put into a Scenario Investment Model (SIM), allowing WPD to choose which solution is best for a low carbon future under various smart grid scenarios.

WPD can combine these six different approaches to understand which combinations will be most effective on their 11kV networks. The model is expected to help WPD and other DNOs predict more accurate load profiles using 48 half-hour periods to analyse the different load and generation on the network throughout the day. When a network planner is using SIM and a fault or network alteration arises on the network, SIM can provide recommendations of techniques that can help resolve the fault efficiently and effectively. It will allow the planners to select the best tool from the toolbox.

FALCON demand response trials

WPD is working with aggregators, like KiWi Power, to recruit trial participants, as well as approaching potential participants directly in the trials area of Milton Keynes. The network that was chosen for the trials doesn’t currently suffer from constraints; however, it will be benefitting from the monitoring to test the six different alternatives of intervention.

The programme also requires adequate incentives to encourage enough users to participate in the programme. WPD will reward those users who successfully participate in its demand response programme when signalled by its control centre. For those industrial and commercial customers on the FALCON scheme, response is triggered during the winter, between 16:00 and 20:00. WPD expects a maximum of 40 hours in a year of demand response events, with each event lasting a maximum of two hours.

In order to monitor and assess the success of each demand response event, WPD requires metering consumption data to be provided for participating sites. A baseline methodology was also introduced to be able to accurately reflect the participating sites’ contribution in response to a WPD dispatch. WPD also created an internal billing system to assess pay for participants on the performance-based service before trials initiated. A back-end call-off system also had to be built in order to send events through to aggregators.

FALCON DSR trials so far

WPD understands that adopting trials to cover a broader region would lead to increased user participation, as the Milton Keynes area alone is not necessarily indicative of business as usual operational potential of demand side response (DSR). New systems and operations also need to be built for control room operation to help with the analysis. WPD believes that there is a skills gap; not only systems but also personnel developments are necessary to be able to implement DR as a business as usual operation for DNOs.

WPD also expects to initiate post-event surveys to determine the programme’s desirability and operational impact on customers. WPD is on track for creating the SIM, with low-level design currently underway. WPD found that there has been difficulty communicating the purpose and importance of FALCON and even communicating with other DNOs on their SIM model has been more difficult than initially expected. In addition to SIM, detailed data needs to be captured before, and after, a DR event to determine the real impact on the network.  According to a recent progress report, WPD aims to use estimates as an alternative to physical substation monitoring. This change in approach will no longer be creating standard profiles through the SIM for non-domestic users but instead, will be using a variety of variables to measure energy consumption. For domestic consumers, WPD aims to narrow down the current 90 demand profile types so additional profile pruning may be necessary.

FALCON demand response trials will start in November 2013 and are expected to deliver valuable lessons from this and other trials to help the network move towards a low carbon future. FALCON is on schedule to test six approaches to a smart network and analyse the outcomes in SIM by 2014. Findings are expected to be shared with other DNOs across the country in 2015.

Transmission Network Use of System Charges: Triad Management Trends

What are Triads?

Triad management carried out from KiWi Power's smart grid operations centre.

Triad management carried out from KiWi Power’s smart grid operations centre.

The Transmission Network Use of System (TNUoS) charges or ‘Triads’ are the three half-hour periods that electricity demand is at its highest across the UK. These periods can fall between the beginning of November until the end of February. Energy supply companies will charge medium-large enterprises significantly more during these three half hour periods to penalise consumption during peak times. Through triad management, medium and large enterprises can lower their energy demand or take their businesses off the network and run on standby generators when the peak half-hour period is expected to occur.

Triad periods are becoming more difficult to predict

Peak demand can be impacted by the end of a working day coupled with street lighting and increasing household electricity demand during winter months. Although historically, entities that forecast Triads such as suppliers, Energy Service Companies (ESCos), aggregators and others have been able to accurately forecast the three peak periods, Triads are becoming increasingly more difficult to predict. While it is known that peak demand will likely occur on some of the coldest days of the year, according to National Grid’s 2012/13 triad data, not a single Triad half-hour occurred in the month of February 2013, which was in fact the coldest February for 22 years.

Furthermore, 2012/13 was also the first year in many to not have a Triad on a Monday or Tuesday. When looking at historical data, most Triad periods have occurred on Mondays, Tuesdays and Thursdays. Over the past 40 years that Triads have been running, almost 35% of these peak periods have occurred on Tuesdays. The most recent Triad periods, which occurred on 29 November, 12 December and 16 January were on a Thursday, Wednesday and Wednesday respectively. One explanation for the lack of Triad periods on a Monday or a Tuesday in the last Triads season may be the unprecedented Triad management that many businesses have undertaken, shifting their demand outside of the Triad period or removing themselves from the grid by running on independent standby generation.

There has been a significant increase in Triad management, from around 600MW to 1.2GW in avoided grid demand across the UK. For example, a hospital in Stevenage and another in Essex are reported to have saved up to £100,000 from effective Triad management.

Expectations for the future

National Grid expects a peak system demand of 56GW for 2014/15, an increase of 1.8% from the previous year with 29% of this demand belonging to industrial and commercial consumers.

Triad charges vary depending on location as some areas of the country, such as Scotland, have a less congested network compared to other areas of the UK, such as London, which experience greater electricity demand.

Triad rates are generally increasing, though the percentage increase is especially significant in areas like London, where triad charges are to increase by 9% from their current rate of £31.17 per kW to £34.08 per kW in London. National Grid is forecasting a further 14% increase is expected in 2014/15 to £38.80 per kW. Northern Scotland currently has the lowest charges but will see an increase of 3% from £10.74 per kW to £11.05, and another 29% increase next year to £14.30 per kW.

Triad Trends image2

Click on image

The bar graph above with the different zones on the x-axis and the tariff changes on the y-axis reveals most of the tariff changes are on average £3.66/kW, with London reaching £4.72 – 30% higher than the average. The tariff charges are largest in zone 12 because re-wiring works are needed on cable circuits.  National Grid expects to recover approximately £280m more revenue through tariff charges in 2014/2015. With this increased revenue National Grid will be able to fund the upgrade needed for the London network while also helping to fund the numerous other scheduled infrastructure projects.

At present, Triad charges can amount to over £50,000 of avoidable annual energy costs and with these prices per kW increasing, these charges are only going to increase. With these expected increases, more companies are expected to actively manage their Triad costs, creating significant cost-savings for their businesses and relieving strain on the National Grid.

Customer-Led Network Revolution

Who is Northern Powergrid?CLNRlogo

Northern Powergrid is the Distribution Network Operator (DNO) for the north-east of England and Yorkshire and is based in Newcastle upon Tyne. With an area of approximately 25,000 sq. kms and a network that consists of more than 61,000 substations, it delivers electricity on behalf of suppliers to over 3.9m customers in the region. Northern Powergrid takes electricity at high voltage from the National Grid and converts it to a lower voltage, making it safe to use in homes and businesses.

The area that Northern Powergrid is trialling represents a diverse range of demographic and geographical areas that can help it analyse the extent as to how beneficial Customer-Led Network Revolution (CLNR) can be and how it can be rolled out across the country. Northern Powergrid was awarded £27m from the Office of Gas and Electricity Markets’ (Ofgem) Low Carbon Network Fund to trial new, low carbon technology on its network.

What is Customer-Led Network Revolution?

Customer-Led Network Revolution (CLNR) is a programme that Northern Powergrid is using to trial a number of smart grid solutions and energy efficient technologies such as solar PV panels, heat pumps, electric vehicles and the installation of 14,000 smart meters in the North East and Yorkshire. The programme will also deploy new technology on the electricity network and implement commercial solutions such as tariffs and different pricing structures. By combining technical and commercial solutions, Northern Powergrid aims to create a successful and beneficial smart grid solution.  CLNR is trialling ‘time-of-use’ tariffs with residential and SME customers to encourage the use of electricity during off peak periods whilst also monitoring the usage of enterprises to establish electricity usage profiles.

CLNR Demand Response Trials

CLNR is trialling the use of demand side response (DSR) with commercial and industrial customers in post-fault situations on the network. If a substation becomes overloaded and causes a blackout, Northern Powergrid would require DSR participants to temporarily reduce their energy loads until the system can be restored.

Northern Powergrid has already run a number of short-term trials over the winter months, requiring customers to be available to turn down their energy consumption from Monday to Friday between 15:00 and 19:00 hrs. Following a signal from Northern Powergrid, a DSR aggregator would then give its participating client 15 minutes to respond. The duration of the demand response call-off was to be four hours. There are a number of different baseline methodologies that Northern Powergrid has proposed to measure the demand response delivered.

If there is a primary substation with occasional loading above firm capacity and the fault coincides at peak times, then Northern Powergrid will put its demand response programme into practice. The aim is to ensure that all customers remain on supply  after a fault on the network by managing  a temporary load reduction until the network is restored.

How have the trials gone so far?

During winter 2011/2012 DSR trials, there were 9 successful events out of a total of 13. The unsuccessful events were caused by unanticipated events on site, including a fire which removed a client during the trial period and a generator failure. One of the benefits of demand response is that reliable portfolios of commercial and industrial customers can be built to deliver the required reduction, providing these sites can be aggregated. The fewer sites there are within a portfolio, the greater the risk is that a single site’s failure will cause under-delivery of the contract.

The focus of this first trial was to test the industrial and commercial arrangements and the effectiveness of DR by working closely with aggregators such as KiWi Power. Northern Powergrid will continue to work with aggregators throughout the winter 2013 trials, while also engaging directly with some industrial and commercial customers in target areas. While large commercial and industrial customers have taken part in the trials, SME customers generally aren’t available to alter their operations during off-peak hours. It is understood that locating customers that are willing to offer four hours of load reduction will reduce the number of businesses able to participate in the scheme. Therefore, Northern Powergrid has suggested using a portfolio of customers, some of which can provide one or two-hour demand reductions or re-evaluating the incentives in taking part.

In 2012, Northern Powergrid used two aggregators to carry out a survey with customers in its programme area. Customers were asked to share their knowledge of DSR and express their willingness to participate. The results revealed that when contact is made with the right person in the business there is low level of understanding of what DSR is amongst the rest of the business. In terms of the most successful demand response strategy, generation seemed to be the preferred option over demand turndown. This is not surprising, given the lengthy duration required of four hours, which would be difficult for demand turndown to maintain. Fortunately the idea of customers having to invest in resources and time did not present a barrier to participating in the programme.

 The project is on track to understanding network and customer flexibility, existing and future loads and also the most effective mix of solutions to reach a low carbon future and is being constantly adapted to fit the changing nature of the programme.

Low Carbon London: UK Power Networks’ Demand Response Trials

Who is UK Power Networks?

Marriott International Grosvenor House

Marriott International Grosvenor House

Distribution Network Operators (DNOs) take high voltage electricity provided from the National Grid and convert it to a lower voltage that is safe for usage in homes and businesses. UK Power Networks is the DNO for London, the South-East and the East of England. UKPN was given £25m of the Office of Gas and Electricity Markets (Ofgem) Low Carbon Network Fund in order to spearhead Low Carbon London (LCL).

Low Carbon London Demand Response Trials

Low Carbon London is a programme aimed at using London as a test bed to develop a smarter electricity network that can manage the demands of a low carbon economy and deliver more sustainable and reliable electricity to the London area. This is just one of many schemes that have been put into action for the UK Low Carbon Transition Plan, which demands a 60% cut in carbon emissions by 2025 in London.

In 2011, the 13 week trial phase of LCL began. Technologies and commercial approaches that are being trialled as part of Low Carbon London include Smart Meters, Electric Vehicles, Heat Pumps, Demand Side Response (DSR) and Active Network Management. These trials seek to develop understanding around how the distribution network can best adjust to the growing demand of electricity whilst keeping carbon emissions to a minimum.

As part of the Demand Response trials within LCL, UK Power Networks identified 13 substations that could become constrained if no action on the network were taken. Low Carbon London sought a minimum of 300 kW of demand per substation to be taken off the network in response to a signal from UK Power Networks. Fast response contracts are also being trialled after faults would have taken place. Additional trials were held in the following winter and summer periods and will continue to run until 2014.

Demand Side Response is a way of altering industrial and commercial consumers’ electricity demand by offering financial incentives. This commercial approach encourages users to consume less energy during peak periods, which will enable power companies to manage the network requirements more efficiently and understand the potential for DSR to support distribution network constraint management.  During the first trial periods of winter 2011/12 and 2012/13, 2MW of DSR was signed up to the trials. By summer 2012, almost 12 MW was being trialled and by summer 2013, the amount of DSR participating in the trials increased to over 17 MW.

Key factors for an assessment of overall contractual value from UK Power Network’s perspective included how many hours in the day a client was available, for how many days a year and also how the total amount of contracted MWs compares to what was delivered when dispatched. The more available a company was, the higher the revenue that could be earned. UK Power Networks was looking to see 90% of requested MWs delivered within the 30 minutes in any single event and that performance levels were managed to above 95% on average.

The role of the Aggregator

There are a number of aggregators, such as KiWi Power, involved in the LCL trials. Aggregators identify prospective customers and initiate customer engagement to discuss how companies may be able to take part in the DSR trials. Following this, aggregators estimate how much demand can be reduced after acquiring information about the customer’s energy usage and how much revenue the end user can earn from implementing a DSR strategy. Site visits are completed to identify the key capabilities of the end user and which DSR solution would be most appropriate. Once the customer is operational, aggregators initiate the selected Demand Response strategy in response to a signal from the network. UK Power Networks signals KiWi Power and other aggregators at the appropriate times, giving clients a 30 minute warning to respond.

Customer Participation in Low Carbon London

There are a number of commercial and industrial sites taking part in the LCL trials across London, including hotels, water facilities and hospitals. One example of a company participating in Low Carbon London is Marriott International. Marriott International was the first hotel chain to sign up to Low Carbon London Active Network Management (ANM) trials. Four of Marriott’s London based hotels (Grosvenor House, Kensington, Regents Park and Maida Vale) took part over the three month trial. These hotels have an automated system in place to turn down chillers and air handling units when dispatched by UK Power Networks using a wireless Siemens device.

Another example of a participant in the programme is Colchester General Hospital, part of the NHS Foundation Trust. The hospital has an agreement in place to run its low voltage diesel generators in response to a signal from UK Power Networks to take the site load off the network. This is done without causing disruption to normal hospital operations. To minimise any site intervention or disruption, the generators are run by full remote control. The Trust is expected to receive significantly high revenues from DSR participation and Triad avoidance and also benefit from enhancing its resilience testing regime. In addition to Low Carbon London, Colchester General Hospital also participates in the Balancing Services program where it provides capacity to the National Grid for system balancing.

Have the trials been successful?

Although the programme and customer engagement has proven to be successful, it is taking time for customers to fully understand the carbon issue the solutions and the benefits for participating businesses. Four seasons of demand response trials have already been held: winter 2011/2012, summer 2012, winter 2012/2013 and summer 2013. In terms of Active Network Management, over 13 site installation surveys have been completed and there are over 24 industrial and commercial participants.

UK Power Networks found that some companies could participate in the events, but not for the duration that was initially requested and aggregation helped to address this issue by ‘stacking’ contracts and dispatching one after another. As some individual sites can’t maintain response during the specified time, so aggregation across sites can help to mitigate this issue.

Specialist power quality monitoring equipment has been installed to increase accuracy and knowledge of when a fault is likely to occur on the network. Twelve of these systems have already been implemented at substations which can send alert signals to initiate a DSR event. All in all, the trials have been a valuable proof of concept programme for UK Power Network’s use of DSR.

Benefits of Demand Side Response to UK Power Networks

The benefits of Demand Side Response to UK Power Networks have the potential to be very significant. Although UK Power Network’s expenditure on maintaining and expanding its network is expected to increase by 18% due to low carbon technologies, this should be offset by reduced unit costs and savings of £38 million, attributed to making use of DSR.

UKPN will continue Low Carbon London trials into 2014 in addition to its other Low Carbon Network Fund projects, such as Flexible Plug and Play. London’s approach, if successful, can be repeated and integrated around the country to help all electricity network operators manage their networks more efficiently in a low carbon future.