Task 15 – Case Study – Orion Network DSM Program – New Zealand

Orion Network DSM Program – New Zealand

This is the 4th article in a series highlighting the case studies of DSM Task 15, Network Driven DSM. This Task demonstrated that DSM can be successfully used to support electricity networks in two main ways:

1) by relieving constraints on distribution and/ or transmission networks at lower costs than building ‘poles and wires’ solutions, and

2) by providing services for electricity network system operators, achieving peak load reductions with various response times for network operational support.

Introduction

Orion New Zealand Limited (Orion) owns and operates the electricity distribution network in the central Canterbury region on the South Island of New Zealand.  Orion is owned by Christchurch City Council and Selwyn District Council.

Orion’s distribution network area covers 8,000 square kilometres of diverse geography, including the city of Christchurch, Banks Peninsula, farming communities and high country regions (see Figure 1).

Figure1_OrionNetworkDSMProgram

Figure 1.  Map of New Zealand showing Orions Network Area (outlined in dark green)

Drivers for the Program

Orion draws energy from the national high voltage electricity transmission network at 10 grid exit points, i.e. the transformers that connect distribution load to the transmission network.  Orion then transports the energy from the grid exit points to approximately 185,000 homes and businesses through the low voltage distribution network.

In New Zealand as a whole, peak and energy demands on the electricity network have been growing at about the same rates from 1990 (see Figure 2).

To cover the costs involved in meeting peak demand, the transmission company in New Zealand, Transpower, charges parties connected to the national transmission network based on an average of
the 12 highest peaks (by half-hour) over a year at the various grid exit points.  This creates an incentive for Transpower customers to minimise peaks.

Figure2_OrionNetworkDSMProgram

Figure 2.  New Zealand Energy Demand and Peak Demand, 1991 to 2007

Since around 1990, Orion has been working actively to limit the growth in peak demand to improve the utilisation of both its distribution network and the national transmission network and consequently reduce the costs per kilowatt-hour of energy delivered to end-use customers in the Orion service territory.

Program Implementation

To achieve the decoupling of peak and energy demand growth in its service territory, Orion has used a mix of direct load control and pricing initiatives.

Direct Load Control

In the Orion service territory, about 90% of residential electric hot water heaters are controlled through ripple control in which control signals to switch the heating elements on or off are transmitted through the power lines to relays at customers’ premises.

Orion promotes two direct load control methods for peak reduction through ripple control:

  • peak control water heating; and
  • night only water heating.

Peak Control Water Heating

Peak control water heating is aimed both at consumers who have water heaters with smaller tanks and at consumers who use larger quantities of hot water.  For these consumers, Orion uses the ripple
system to switch off water heating elements during peak loading periods, and cycles through up to 16 groupings of water heating load to ensure sufficient heating is provided.

Peak load control is used when the demand in Orion’s network area reaches a certain threshold;  in 2007, this was 570 MW.  When the load approached this level, Orion commences switching off water heaters in groups to keep demand from exceeding the threshold level.  To limit the potential impacts on customers, Orion cycles the controlled water heaters, switching on one group of water heaters while switching off a different group to maintain the load below the threshold level.

To maintain service standards and encourage appropriate design of hot water systems, Orion has set service level targets whereby it aims to have individual water heaters switched off for no more than seven hours per day, and no more than four hours in any seven hour period.  The heating elements in water heaters with tanks larger than 100 litres can be switched off for several hours without customers noticing any reduction in the supply of hot water.

During the period 2005 to 2007, Orion used peak control to switch water heaters for an average of 54 hours a year, typically in the winter months (June to August).

Night Only Water Heating

Night only water heating is aimed at consumers who have water heaters with larger tanks.  Orion uses the ripple system to switch on these heaters only at night, permanently shifting this load away from peak times.

This option has been so successful that Orion must progressively stagger switching on the night water heater load over a period of time to avoid setting night-time peaks.  In some areas, Orion
uses peak control to lower loading levels while night water heating load is being turned on.

Orion also provides an option that includes an afternoon heating boost to night only water heaters to ensure that hot water is available in the evening.

Pricing Initiatives

Controlled Water Heating Loads

Customers with controlled water heating in the Orion service territory receive pricing incentives delivered through their electricity retailer.

Table 1 shows tariff schedules for the electricity retailer Contact Energy as at May 2008.  Contact customers on the Controlled Load tariff save 10% on the standard Anytime Use tariff, under which water heaters are not controlled.  Under the Day/Night – Night tariff, used for night only water heating, customers pay only about 50% of the Anytime Use tariff.

Table1_OrionNetworkDSMProgram

Commercial and Industrial Loads

Sometimes the use of direct load control is not enough to keep the load on the Orion network from exceeding the required threshold.  During periods when loading levels reach a set threshold, Orion
initiates a second load reduction measure based on peak demand pricing and targeting larger commercial and industrial loads.  These periods are called “control periods”.

Orion has estimated its long run average incremental cost to deliver electricity at peak times, and reflects this cost in its peak demand charges.  With this cost-reflective pricing approach, the decision to reinforce the network for load growth is effectively passed to consumers – they can elect to use energy at peak times and accept the cost of delivery, or avoid peak times and save.

The start and end of a control period are signalled to consumers in real-time via ripple signals, text messages and emails.  Orion identifies control periods for major customers (those with half-hour metering and loads greater than 250 kVA), and records their average loadings during these periods (typically over a total of 80 to 100 hours per year).  This average loading then forms the basis of Orion’s control period demand charge, which is currently set at NZD139.20 per kVA per year (for delivery only).  Over the duration of the control periods, this equates to a delivered cost of electricity of NZD1.50 to NZD2.00 per kWh, compared with the normal delivered cost of electricity of NZD0.12 to NZD0.20 at other times.

Control periods vary in length and the signal is withdrawn when loading levels fall to lower levels.  To help customers respond, Orion provides 10 minutes advance warning for control periods and ensures that each control period lasts for at least 30 minutes.  Control periods are only signalled during the
core winter months when loading levels peak.

‘General Connections’ Loads

Orion also uses a similar pricing approach for smaller ‘general connections’ loads, using ripple signals to identify peak periods for demand pricing, and applying charges based on each electricity retailers’ reconciled allocation of grid metering during these periods.

Results

Orion has been one of the most successful electricity distributors in New Zealand in minimising peak demand growth.

Figure 3 shows the results of Orion’s efforts, with a noticeable improvement in the load factor (ratio of energy delivered to peak demand) after 1990.  Note that the demand is the maximum individual half-hour value, which is somewhat volatile, and consequently the load factor can fluctuate from year to year.  On average, the trend in Orion’s load factor has been to increase by 0.7% per year since 1990, (50.7% in 1990 to 60.9% in 2008) but this rate of growth has slowed in recent years.

 Figure3_OrionNetworkDSMProgram

Figure 3.  Orion Energy Deliveries and Peak Demand, 1980 to 2008

Orion has achieved a 90% penetration for controlled water heating in its service territory.  Figure 4 shows the impact of peak control measures on a typical cold winter day.  On this graph, the blue line shows the actual load level and the red line is a calculated estimate of the load level that would have occurred if peak load control of water heating had not been done.  Figure 4 also shows the effect of two control periods in causing end users to shed load.

Figure4_OrionNetworkDSMProgram

Figure 4.  Orion Daily Load Management Summary, Thursday 28 June 2007

Because of the DSM measures implemented, Orion is to a high degree able to prevent peak demand from exceeding a set level.  Figure 5 shows the demand in the Orion service territory for various days in June 2007.

Figure5_OrionNetworkDSMProgram

Figure 5.  Peak Demand on Orion’s Network on Different Days in June 2007

Figure 5 shows that roughly the same peak value is obtained on different days as peak demand is shifted to off-peak periods, either between the morning and afternoon peak or after the afternoon
peak.  This peak shifting results in lower payments to Transpower and has reduced the requirement for investment in Orion’s own network.  These effects lead to lower network charges to Orion’s end-use customers.

If Orion’s load factor was still at its 1990 value of 50.7%, the peak demand on the network would be 750 MW instead of 630 MW, an increase of 120 MW.  Orion estimates that the additional cost for delivery of this peak load would equate to approximately NZD12 million per year for distribution and NZD6 million per year for transmission (or approximately 11% more).  This is based on an estimated Long Run Average Incremental Cost (LRAIC) of new transmission capacity of around NZD50/kW and a distribution LRAIC of NZD100/kVA per annum.

Peak load reduction can also provide additional savings from a lower investment requirement for peaking generation (though generation capacity has not been a constraint in the New Zealand market
until recently).

Download case study here

This article was contributed by David Crossley, Managing Director of Energy Futures Australia Pty. Ltd and Senior Advisor at The Regulatory Assistance Project.  For more information on this case study and others, visit Task 15, Network Driven DSM at:

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