3. Electricity Generation
3.1 Introduction
New electricity generation growth is predicted to be on average 1.4% p.a. for the "Most Likely" case (2004-2025). There are a number of issues relating to this lower figure particularly when compared to the Electricity Commission (EC) published demand data. The main differences are that SADEM:
- incorporates interaction between electricity demand and prices
- incorporates the effects of price competition between electricity and other energy sources across all sectors
These differences are being reviewed with the EC. Also the SADEM electricity module is being reviewed in association with Covec and Energy Link.
Furthermore on the generation side there has been significant year-to-year variability in emissions. This is primarily due to the annual variability of hydro inflows.
Electricity demand growth is modelled to be significantly lower than current growth (1.9% p.a. for 1999-2004) for a number of reasons:
- Electricity demand by the Industrial and Commercial sector is expected to be slightly suppressed. Current growth of 1.6% p.a. (1999-2004) is expected to drop to 1.4% p.a.
- No further electricity growth is expected for the Metals sector beyond 2009. Comalco in particular forecasts flat demand. Current growth is 0.5% p.a. (1999-2004).
- Forestry is currently growing very strongly at 6.4% p.a. (1999-2004). This growth rate is forecast to drop for 2004-2010 to 1.3% p.a. Forestry however is set to expand with a projected increase in wood harvested from 2010.
- Residential growth is projected to remain steady at 1.7-1.8% p.a.
Growth in electricity generation is essentially provided for by installation of, cogeneration, geothermal, GCC plant (e3p), wind and upgrades to existing hydro. New hydro doesn't feature in the modelling scenarios until after 2010. The merit order and new generation profiles are provided in Figure 9 and Table 2. Table 2 should be taken as illustrative. For each generation type there exists a range of capital development possibilities each with their own price and likely level of national availability at that price.
Figure 9: Indicative New Plant Generation Costs
→ Full size version Figure 9 [10 KB GIF]
Table 2: Indicative New Plant Generation Profiles1| Generation Type | Total Cost c/KWh | Potential Capacity MW | Potential Supply GWh pa | Potential Average Load % |
| Hydro | 7.5 to 9.0 | 575 | 3000 | 60% |
| 11.0 to 13.0 | 190 | 1000 | 60% |
| Geothermal | 5.5 to 6.5 | 385 | 3000 | 89% |
| 8 | 45 | 350 | 89% |
| Cogeneration | 2.5 to 5.0 | 350 | 1700 | 55% |
| Wind | 6.5 to 7.0 | 1220 | 4800 | 45% |
| 9.0 to 11.0 | 950 | 3300 | 40% |
| Gas Combined Cycle | 5.5 to 7.0 | 785 | 4800 | 70% |
| Coal (no carbon tax) | 8.0 | 1000 | 7000 | 80% |
| 10.5 (FGD) | 150 | 1050 | 80% |
| Distillate | 18.5 to 24.0 | no limit | no limit | 75% |
3.2 Wind Generation
Wind generation as a resource is expected to become much more significant. Due to the high proportion of hydro currently established, New Zealand is significantly advantaged in that it is able to leverage off the "fuel reserve" (i.e. dam storage) for inter-seasonal and daily variability.
3.3 Gas Generation
During the 1990's growth in gas fired electricity generation was strong at 4-5% p.a. Much of this was due to the ready availability of relatively cheap Maui gas. In addition the technological improvement in high temperature materials and bypass designs allowed a significant improvement in gas turbine efficiencies. Combined with steam generation units on the gas turbine offtake, known as gas combined cycle (GCC), efficiencies in the order of 50-55% are now obtainable. This compares well with coal fired steam generation where efficiencies are typically only 30-40%. Also capital costs for GCC plant are less than for new coal plant per MWh of generation.
Considerable uncertainties exist around gas availability. Because New Zealand is isolated, gas is only currently available from fields developed locally. Current reserves are projected to last till 2020 but not at a level that will sustain the volume required for electricity generation. The level required for this is only likely to be sustainable to 2012-2015, unless there are significant new discoveries.
If an LNG (liquefied natural gas) terminal were to be developed it would mean that gas could be imported by ship. LNG is a capital intensive and expensive option, compared to domestic gas production. Although costs are reducing in this area as technologies improve.
3.4 Cogeneration
There is a further uptake in cogeneration, particularly with the availability of small scale turn-key plant and the recent increases in electricity prices. Cogeneration is a system for producing industrial heat, with electricity generated as an additional saleable product. Fuel for cogeneration modelled in these projections comes from natural gas and woody residues. Cogeneration has been especially popular in the wood processing industry where such residues occur, particularly in timber milling/kiln drying operations. And in the dairy industry where gas fired turbines generate electricity and provide large amounts of secondary steam for heating and sterilisation purposes.
3.5 Geothermal Generation
With the rising cost of electricity a number of existing and new geothermal fields are now becoming viable for development. Geothermal generation has been reasonably well established for some time and New Zealand is well mapped in terms of locating and developing this resource.
Greenhouse gas releases may become an issue for this form of generation. Each geothermal field has its own release characteristics which are principally dependant upon the temperature of the field. Once this pressure is released during generation much of the carbon dioxide absorbed in the geothermal water used to run the turbines is released to the atmosphere.
Geothermal generation is however relatively inefficient at 10-15% conversion due principally to the relatively low temperatures involved (200-250ºC).
GHG releases ranging widely in the order of 3% to 60% of that for a coal fired power station per MWh generated are typical. Currently the weighted average is about 11% (or 100 tCO2/MWh). However the current model only includes CO2 emissions from existing, but not new, geothermal.
Back to Top