1. Summary
This outlook for electricity dry year security of supply completely updates the first security outlook published in December 2002.
These outlooks are designed to make information on the future security of supply risks widely available. They are based on many assumptions, many of which may prove to be invalid. As such, the outlooks are not predictions. In respect to winter 2004, ELL understands that the MED will, in due course, be carrying out more detailed analysis of the security risks and making the results of this work publicly available.
The December 2002 outlook assumed unconstrained thermal fuel availability through 2003, and on the basis of this assumption, the security risks were assessed as low through 2003. In the event, low thermal fuel availability contributed to risks rising significantly as low hydro inflows led to declining lake levels.
For this outlook, two scenarios were developed by ELL and discussed with the MED to evaluate the supply risks facing the New Zealand electricity industry over the next four years. Details of the two scenarios are summarised below:
Table 1: Scenarios
| Scenario | Description |
|---|
| Base Line | Base line scenario, demand growth of 2.0% pa from the 2002/2003 March year, assuming new generation assets as detailed in section 5.2 and no demand response. All other assumptions as summarised in section 1.1, details of which can be found in section 5. |
| High Demand | As for Base Line but with demand growth of 2.5% pa. |
Each scenario was run for each April/March year over the period April 2004 through March 2008 using 72 years of historical weekly inflow data in each year and each scenario.
The scenarios focussed on assessing dry year risks and not price effects. It has been assumed that there will not be constraints on thermal fuel availability through to March 2008. Given the recent steps that have been taken by thermal generators to secure fuel, this appears to be a reasonable assumption for 2004. In later years, the availability of thermal fuel is less certain. Clearly if thermal fuel constraints play a part, then risks will rise above those indicated in this report.
In addition to the dry year risks assessed in this report, additional risks that have not been modelled in detail include those that could arise from numerous events occurring in combination such as sustained Grid outages on major lines (e.g. the HVDC Link), sustained plant outages and extreme demand. However, a key assumption in the modelling is that the EC, working with the industry, will allow for some of these events by ensuring that lakes are not planned to be run down to empty. This is discussed further in section 6.2.
1.1 Assumptions
A summary of the key assumptions applied in the modelling is shown below. Detailed explanation of these assumptions can be found in section 5.
- Compound demand growth is modelled in line with the demand scenarios detailed in section 5.3, base line demand growth of 2.0% pa, high 2.5% pa.
- Demand response, including both response to high prices by larger consumers and calls for voluntary savings, were not modelled in this update.
- Hydro Generators will attempt to optimise the value of their water in individual lake systems to ensure that they do not run out. This means that hydro storage is managed within dry year security of supply parameters specific to their hydro systems, i.e. making "optimum" use of their water.1
- Smaller generating stations will tend to offer available capacity at base load in line with historical market behaviour.
- Smaller generators' plant volume is offered based on historical averages to ensure dispatch to realistic schedules.
- New generators will tend to offer below the margin rather than offering at their total cost in order to get dispatched, thus reducing their risk and meeting their contractual obligations for fuel, retail load and hedge contracts.
- The maximum transfer capacity of the HVDC link will remain at approximately 1,040MW northward and 626MW southward, as measured at the sending end in each case. Other key lines have been modelled at their advised capacity.
- The maximum transfer capacity2 on the BPE-HAY group of lines is modelled at a maximum of 930MW.3 At time of high southward flows down the NI, it is often these lines which reach their combined load limit, thus preventing further southward flows on the HVDC Link.
- All existing major thermal and hydro plant available to run as required, except for scheduled planned outages.
- The EC will take steps to achieve or get close to end of year storage (early April each year) of at least 2,100GWh in the SI.
- No consideration of any short term generator strategy that may influence outcomes outside of normal market conditions.
1.2 Supply Risk
The results of the modelling suggest that given all of the assumptions above, dry year security of supply, using specific storage criteria, can be maintained assuming 2% demand growth per annum. It becomes more difficult to maintain dry year security of supply under the 2.5% demand growth per annum scenario.
The results also suggest that reserve generation will be required in at least one inflow sequence in each of the four years considered.
There is no demand response modelled in either of the scenarios which means that even under the 2.5% growth assumption there is room for some demand response to high prices during a dry year to assist in preserving supply. However, against this, it should be noted that the modelling does not take into account random plant and line outages that could affect supply, and the subsequent need for demand response, from time to time.
1.2.1 1-in-60 Dry Year Security
The EC's target of 1-in-60 dry year security means, in simple terms, that there should only be a "shortage" 1 year out of every 60 on average in the long term. However, the difficulty arises when one tries to define a "shortage" in the face of uncertainty about the nature of events that could take place in the future.4 Because of this, our modelling is based on the assumption that the future offer behaviour of generators is similar to that of the past, with key SI hydro lakes being managed such that there is very low risk of them running empty - this is consistent with our observations of how these lakes are actually operated. The modelling assesses the security of supply risks under this assumption about offer behaviour. The modelling is not driven off the 1-in-60 criterion.
This report examines four indicators of "shortage" in relation to the modelling of the two scenarios described in Table 1.
- SI Storage;
- Frequency of reserve generation dispatch;
- Demand response indicators;
- Capacity margin.
1.2.2 SI Storage
This criteria for shortage is based on how often SI storage falls below 300GWh and 500GWh in each scenario and year modelled.
Table 2 below shows the number of inflow sequences, from 72 modelled, in which SI Storage falls below a level of either 300GWh or 500GWh.
Table 2: SI Storage Minimum Levels
| Year | 2% pa Demand Growth | 2.5% pa Demand Growth |
|---|
| SI Storage < 300GWh | SI Storage < 500GWh | SI Storage < 300GWh | SI Storage < 500GWh |
|---|
| 2004/2005 | 0 | 2 | 1 | 3 |
| 2005/2006 | 0 | 1 | 0 | 3 |
| 2006/2007 | 0 | 2 | 1 | 2 |
| 2007/2008 | 0 | 3 | 1 | 3 |
SI storage falls below 300GWh at most once in each year in each demand scenario but does fall below 500GWh more often.
1.2.3 Frequency of Dry Year Reserve Generation Dispatch
Table 3 below shows the number of inflow years, from 72 in total, that Whirinaki runs in each modelled year for each demand scenario.
Table 3: Whirinaki Runs
| Year | 2% pa Demand Growth | 2.5% pa Demand Growth |
|---|
| 2004/2005 | 2 | 4 |
| 2005/2006 | 2 | 4 |
| 2006/2007 | 2 | 3 |
| 2007/2008 | 1 | 2 |
Whirinaki does not run often, consistent with the government's recent announcements. However, the major thermal stations such as Huntly must run hard and early in the driest years in order to achieve this outcome. This reflects a key assumption in the modelling - that the new EC will be able to achieve this degree of response by thermal generators.
Although not obvious from the results, it is evident that reserve generation has additional value in being able to backup other plant when required or in providing additional services such as spinning reserve - refer section 7.6.
1.2.4 Demand Response Indicators
Dummy generators are used in the modelling to represent "non-supply" which can also be taken as an indicator that some demand response is required. Two non supply generators are modelled, one in the NI and one in the SI. Both are offered at $10,000/MWh.
Non supply generation did not get dispatched at all in either of the scenarios indicating that there would be no demand response required, even in the drier inflow years. This is not to say, however, that there would be no demand response in reality. When electricity spot prices climb in a dry year there may well be reduction in demand by organisations that are exposed to these prices.
1.2.5 Energy Supply Versus Demand
Another approach to examining security of supply is to look at the aggregate energy available and compare this with demand. The following chart shows the total potential energy from the 20015 inflow sequence plus all other available energy, i.e. assumes all stations are run at available capacity.6 The chart shows the demand as total energy rather than as peak demand.
Figure 1: Potential Energy Supply Versus Demand under the 2001 Inflow Sequence
The above chart is interesting in as much as it indicates the potential for a brief supply problem at the end of June 2004. On face value, one might think that hydro storage could more than adequately cover this temporary shortage, also providing that little bit extra during daily demand peaks. However, it should be noted that the above supply and demand is taken on an aggregate national basis, i.e. it does not reflect any supply problems that can be caused by regional constraints in the transmission Grid.
The chart below shows the potential output from all SI generators under the same "dry" inflow sequence charted against SI demand. The analysis also assumes full southward capacity transfers on the HVDC Link of 626MW at the sending end. Accordingly this chart takes account of the constraint imposed by the HVDC Link.
Figure 2: SI Demand Versus Available Energy under the 2001 Inflow Sequence
Given the limitations on southward transfers on the HVDC Link, it becomes evident that SI demand would have to be met by SI storage when the capacity margin is shown as being "in the red." In this example, a target capacity margin could be calculated where SI demand exceeds the deliverable energy from inflows.
Simplistically, dry year security of supply could be accommodated by ensuring at least the capacity margin is maintained as storage in the SI lakes. This approach, however, would be overly simplistic because, amongst other things, if the capacity margin were calculated against the driest year in 60, and storage limits enforced, there would be significant spill in other inflow years.
The conclusion is that the capacity margin over the nation as a whole is only just sufficient for a dry year, such as 2001, if nothing else goes wrong, and it is insufficient in the SI due to constraints on the Grid.
1.2.6 Supply Risk Indicators
The supply risk indicators show the following:
- forecast SI storage does get drawn down below 500GWh in at least one, but not more than three, inflows sequences in both scenarios over the next four years;
- reserve generation at Whirinaki is required in at least one, but not more than four, inflows sequences in both scenarios over the next four years;
- the reserve generation is sufficient to eliminate the need for demand response, but does not preclude it;
- the capacity margin analysis emphasises the management of SI hydro storage lakes is critical in order to maintain security of supply.
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