5. Key Assumptions
5.1 Project Aqua
For information on Project Aqua we have relied heavily on Meridian Energy's resource consent application material and information obtained from Meridian Energy through MED requests or discussions. This section sets out key information about the Project Aqua proposals that we consider is relevant to modelling and analysis of its potential contribution to the economy.
The Project Aqua scheme will utilise the lower reaches of the Waitaki River by diverting the river flows at Kurow, with about 70% of the average inflows going down a canal, and the balance going down the existing Waitaki River bed.
The proposed 524MW scheme consists of a 60km long canal on the south bank of the river, a canal intake at Kurow, six power stations each with a head of approximately 30m located along the canal system, bypass structures at each station to allow generation during machine shutdowns, and outfalls back to the river near Black Point and just above the Waitaki State Highway 1 Bridge.
Project Aqua is planned to be constructed in two stages.
- The first stage involves the construction of the intake and the canals linking the three stations located between Kurow and Black Point. This stage would be constructed and operated first, requiring an initial outfall discharge to the river in the vicinity of Black Point. We have assumed that Stage 1 is completed by October 2009.
- A second stage would follow and comprise constructing the remaining canals and three stations between Black Point and the outfall discharging to the river above the State Highway 1 Bridge at Steward Road. We have assumed that Stage 2 is completed by July 2011.
Figure 1 shows the current flows down the Waitaki River downstream of the existing Waitaki Dam out to the sea.
Figure 1: Current Lower Waitaki River Flows
Full size image of Figure 1 available.
The current annual average flow in the Waitaki river is approximately 360 cubic metres per second (cumecs). The current minimum release from the Waitaki Dam, under Meridian Energy's existing resource consents, is 120 cumecs. Figure 2 shows a stylised view of the canals and power stations of Project Aqua overlaid on the Lower Waitaki.
Figure 2: Lower Waitaki with Canals Overlaid
Full size image of Figure 2 available.
Under the proposed scheme the minimum flow in the river would vary between 100 and 140 cumecs depending on the month. The remaining flows would be available to flow through the canal system and drive the six hydro-electric power stations.
The timing of capital expenditure and production for the scheme assumed for this analysis is outlined in the following Table 1.
Table 1: Project Aqua Timing Assumptions| Year | Capital Expenditure | Expected Annual Production |
| 2006 | $120m | |
| 2007 | $120m | |
| 2008 | $240m | 140GWh |
| 2009 | $240m | 1117GWh |
| 2010 | $240m | 1897GWh |
| 2011 | $120m | 2779GWh |
| 2012 | $120m | 3000GWh |
| Total | $1200m | |
The capital expenditure estimates are based on Meridian Energy's assessment of a total project cost of $1200m. We have no detailed information on the timing of capital expenditure. However, it seems reasonable to assume that the total cost would be spread over a period from the start of construction in 2006 to post completion in 2012.
The production estimates are based on our understanding of the station commissioning programme outlined in the report Project Aqua - Assessment of Environmental Effect produced by Meridian Energy in May 2003.
For this analysis we have assumed that Project Aqua is capable of delivering, on average, 3000 GWh per annum. This matches the information contained in the Meridian Energy documents. It is also supported by our analysis of hydrological conditions over the period 1980 - 1999.7 We note that analysis using all available hydrological data back to the 1930s suggests slightly lower average output of approximately 2800GWh per annum. During the course of this project we have become aware that there are some uncertainties about the modelling of expected generation from Project Aqua and the likely output8 in extreme dry years. More analysis would be necessary to establish full confidence in this data.
5.2 Electricity Demand
Electricity demand in New Zealand has been highly correlated with economic growth and since the oil shocks in the 1970s electricity demand growth rates have averaged about 2% per annum. A range of independent energy forecasts have suggested likely average growth in the range of 1.2% to 2.6%9 per annum through the next fifteen years.
For this analysis we agreed with MED to use the electricity demand growth assumptions outlined in Figure 3.
Figure 3: Projected NZ Gross Electricity Demand
Full size image of Figure 3 available.
Plausible variations from this demand forecast would have consequential impacts on this analysis. However, we consider that the differencing approach taken in this analysis means that variations in the demand forecast are likely to have second order impacts, and are unlikely to alter overall conclusions.
For the purpose of our scenario analysis we have assumed that the price elasticity of demand is low, that electricity price differences between the scenarios are less than 10%, and that consequently, electricity demand is similar in both scenarios.
5.3 Thermal Fuel
One of the key differences between the With and Without Aqua scenarios is fuel consumption. If Aqua does not proceed it is likely to lead to more consumption of thermal fuels in both the short and long term. Fuel costs are also a key determinant in evaluating long run unit costs of new power station development options.
Thermal power station development in recent years has been dominated by high efficiency combined cycle gas turbine plant (CCGT), with power stations at Stratford and Otahuhu fuelled largely from the giant Maui gas field.
Early depletion of Maui gas and the expected cost of developing alternatives at Pohokura and Kupe will see gas prices rise well above the observed range of $2.50 to $3.50/GJ evident through the last ten years. The focus for thermal fuel development is therefore likely to shift to coal.
Our key assumptions for thermal fuel prices were agreed with MED as outlined in Table 2.
Table 2: Thermal Fuel Assumptions| Station | Fuel | Price per GJ |
| Huntly | Coal | $3.50 |
| New Plymouth | Oil | $11.00 |
| Whirinaki | Oil | $15.00 |
| CCGT | Gas | $5.00 |
| West coast | Coal | $1.20 |
| Southland | Lignite | $0.60 |
In practice, thermal fuel prices will vary over the forecast period. We have therefore tested the sensitivity of our conclusions to variations in fuel prices.
5.4 Carbon Emissions
Carbon emissions will also vary significantly between the two scenarios. For our analysis we have calculated the level of emissions and valued them at $15 per tonne.10 We have also used this value in our long run unit cost calculations for thermal power station options.
The emission rates for different fuels used in this analysis are summarised in Table 3.
Table 3: Carbon Emission Rates| Fuel | Emission Rate |
| Huntly Coal | 91,200 tonnes/PJ |
| West Coast Coal | 88,800 tonnes/PJ |
| Lignite | 95,200 tonnes/PJ |
| Oil | 74,800 tonnes/PJ |
| Gas11 | 52,800 tonnes/PJ |
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