• Home
• Energy & Resources
• Energy Modelling
• Modelling Papers
• Supply Cost & Availability
• Fossil Fuel Generating Costs
• 2. Technologies

• Energy Modelling

• Modelling Papers

• Supply Cost & Availability

• Renewable Energy: 2005 Edition
• Fossil Fuel Generating Costs
• Renewable Sources 2002
• Generating: Technical Note

• 2.1 Electricity Generation Cost Estimates
  • 2.1.1 Carbon Charge
  • 2.1.2 Technology Lead Times

Technologies have been chosen that are expected to be included internationally in fossil fuelled electricity generating plant over the next 25 years with a focus on those currently commercially available. These technologies are:

• Supercritical pulverized coal fired boiler (using bituminous or sub-bituminous coal, or lignite) with or without flue gas desulphurization (FGD)
• Natural gas fired combined cycle gas turbine
• Natural gas fired advanced gas combined cycle turbine
• Natural gas fired gas turbine
• Natural gas fired advanced gas turbine.

The size of plant included in this study is limited to that likely to be used for wholesale generation of electricity. Significant changes since the May 2002 report are:

• Trend towards supercritical boiler and turbine plant with slightly higher capital cost but greater efficiency.
• Generally higher fuel prices.
• Higher gas turbine efficiencies.
• Lower FGD costs.
• Change in currency exchange rate (to $NZ1 =US$0.60 from US$0.42).
• Costing for larger coal fired plant (500 MW instead of 400 MW) and for larger advanced gas turbine plant (230 MW instead of 120 MW). This is in line with the trend overseas for larger plant while recognising the New Zealand situation and its limited ability to cope with large unit sizes of plant. The same size advanced combined cycle gas turbine plant, using a state of the art advanced gas turbine, has been costed. A smaller combined cycle gas turbine plant, using a conventional design gas turbine (250 MW instead of 400 MW) has been costed. Conventional gas turbines are generally smaller than state of the art advanced machines.
• Inclusion of costing for a range of coals of varying rank, and for a 150 MW coal fired plant on the West Coast of the South Island. It is probable that this is the maximum size of plant that could be accommodated without major upgrades of the transmission system from the West Coast.

Capital costs, plant efficiencies and operating and maintenance costs for the chosen technologies are given in Table 1.

Overseas cost data has been adjusted for New Zealand conditions. The adjustment procedure is outlined in Appendix D, with all costs adjusted to New Zealand dollars as at September 2003. The costs are indicative only and individual plant costs will vary according to the site, special conditions and constraints. Typical plant sizes have been chosen.

Points to note:

• The unit cost of electricity is a levelized cost estimated in a commercial context with a 7.5% discount rate (taken to be the post-tax real WACC). Levelized cost is the time value of all costs converted to a uniform series of deposits spread over the entire life of the investment. It takes into account the total discounted cost of producing the electricity (capital, operating and maintenance and fuel costs) and the total amount of electricity produced over the life of the plant, and distributes these costs over the operating life of the station. This levelized cost is matched by revenue from the sale of electricity which is taxed at the company tax rate (33%). However, this tax is partly offset by the asset depreciation tax shield. This net tax position is shown as "Tax" in Table 2 and Table 3 in this report and "Other" in the May 2002 report. Appendix A provides a detailed explanation of how the unit costs have been derived. Although the unit costs have been estimated in a commercial context, this appendix indicates how the estimates could also be used in a national cost benefit analysis.
• The output and efficiencies quoted for gas-fired plant apply for a natural gas fuel. Natural gas firing gives a slightly higher output than distillate firing. The efficiency is also slightly higher (by about 3%) when burning gas as opposed to distillate, i.e. multiply the efficiency given in the text by say 0.97 for firing by distillate.
• No carbon charges have been included in the fuel costs.
• The capital costs quoted generally apply only to plant that is close to the size of plant specified. For generating plant with a different MW output, capital cost scaling factors are outlined in Appendix E.
• Costs do not include investigations, obtaining resource consents, transmission costs and losses.
• All efficiencies are based on the higher (or gross) heating value (HHV) of the fuel to enable direct comparisons to be made between the technologies. The difference between this and the lower (or net) heating value is the release of heat from the condensation of water in the products of combustion.

Note 1: For a pulverized coal plant without FGD deduct $170/kW from the capital cost. O&M costs are reduced by approximately 10% and there is an approximate 2% gain in efficiency.

Note 2: Costs are in September 2003 New Zealand dollars.

2.1 Electricity Generation Cost Estimates

Indicative current electricity generation cost estimates (2003) are shown in Tables 2 and 3. In these examples a discount factor of 7.5% has been used over a 20-year plant life. Fuel prices used are $5.00/GJ for gas, $2.50/GJ for bituminous coal on the West Coast (SI) and $3.50/GJ for elsewhere in New Zealand, $3.50/GJ for sub-bituminous coal and $1.50/GJ for lignite coal. (These prices have been discussed and agreed with the MED.) The net load factor has been assumed to be 90%. Supercritical pulverised fuel (pf) plant has assumed to be installed except for the West Coast (SI) where subcritical pf plant has also been considered. (Huntly power station is a subcritical pf plant. Gas turbines and combined cycle gas turbines recently installed in New Zealand tend to fall into the "advanced" category.) As coal plant without FGD would be an option if low sulphur coal were available, costing estimates for such plant are included (see Table 3). Cost estimate sensitivities are detailed in Appendix B.

2.1.1 Carbon Charge

A carbon charge has not been included in the above estimates. However to illustrate the effect of say, a $15/tonne carbon dioxide emission charge, the estimated cost of electricity generated from gas would increase by about 0.7c/kWh, from bituminous and sub-bituminous coal, 1.2c/kWh and lignite 1.3c/kWh.

2.1.2 Technology Lead Times

As well as costs, lead times from project conception to commercial operation have been considered. These can have a significant effect on the viability of any electricity generating plant project. Appendix F gives details of the analysis and indicative lead times for the different technologies are summarised in Table 4.

Lead times can vary widely, but are likely to be around two and a half years for an open cycle gas turbine, around four and a half years for a combined cycle gas turbine and around six and a half years for a coal fired station.