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• 6. Development Options

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• 6.1 Context
• 6.2 Cost of Capital
• 6.3 Location Factors
• 6.4 Hydro Development Options
• 6.5 Wind Development Options
• 6.6 Geothermal Development Options
• 6.7 Thermal Development Options
• 6.8 Cogeneration
• 6.9 Summary

6.1 Context

A significant number of potential new generation options exist in New Zealand with varying levels of confidence in the underlying economics and possible timing. The uncertainties include:

• Doubts over the final Maui gas redetermination outcome, delays in bringing Pohokura gas on stream and current difficulties faced by potential investors in securing long term gas contracts;
• The potential time and effort involved in securing Resource Management Act (RMA) consents for new generation projects;
• The level of carbon tax likely to be established from 2007;
• Government policy in support of renewable energy projects;¹²
• Technical and commercial risks in developing some supply technologies.¹³

In assessing likely future generation projects, we have taken into account a number of factors including published information from electricity companies and the Ministry of Economic Development, and our own knowledge of specific development options, technology costs, and fuel resource availability and costs.

The availability of low priced Maui gas has constrained electricity supply costs and prices to relatively low levels since the late 1970s making alternatives such as coal, hydro, geothermal and wind unattractive. This situation is rapidly changing and the current gas outlook is likely to limit gas-fired development opportunities within our modelling horizon to 2020.

6.2 Cost of Capital

A key ingredient to assessing the cost of electricity generated from new projects is the cost of capital required to fund the projects. The conventional approach to assessing the cost of capital for projects is to calculate the weighted average cost of capital (WACC) for the firm investing in the project.¹⁴

The WACC for firms investing in the New Zealand electricity market will vary with the investor perceived risks associated with those firms. For the analysis contained in this report we have assumed that investors in new power station projects are likely to be a combination of existing generator participants or new entrants with similar costs of capital.

The WACC is used in this analysis to calculate unit costs, rank projects and reach conclusions about the level of wholesale electricity price that would justify a particular investment proceeding. It is therefore important that this forecasting exercise mimic how potential investors would assess their investment opportunities. Individual investors will approach the issues of project evaluation and assessing project risk in many different ways. Some will look for positive net present values, some will factor explicit risks into project evaluations and some will assess projects using a hurdle rate of return that is higher than WACC.

Appendix 1 outlines our analysis of the likely range of WACC for these firms. For this analysis we have chosen to calculate power station unit costs using a weighted average cost of capital of 9.0% real post-tax. We have chosen a value towards the upper end of the plausible range of WACC, as a relatively simple means of capturing the diverse range of investor assessments. This approach has been supported by an independent analysis of this issue provided by Castalia.¹⁵

6.3 Location Factors

The New Zealand wholesale electricity market includes a locational pricing arrangement, such that wholesale electricity prices vary around the network, reflecting transmission losses and constraints. This means that power station options will have different economics at different locations around the grid. Power stations in the Auckland area will typically realise higher prices for output than power stations in the lower South Island, for example. To recognise this factor in our analysis we have used analysis provided by Energy Link¹⁶ to estimate the location factor for each power station development that we have identified depending upon the location of the project. The location factor is expressed as a scaling factor applying to each node that reflects the average spot wholesale price expectation at that node relative to the Haywards node in the Wellington region.

We have used the location factor to adjust the long run unit cost for each power station to establish an equivalent price at the Haywards reference node. This means that all projects can be ranked in a merit order regardless of location.

6.4 Hydro Development Options

Large-scale hydro developments have traditionally underpinned New Zealand's electricity system. Clyde power station, commissioned over ten years ago, is the newest large-scale scheme. Until recently, it was considered that large-scale hydro developments were unlikely to be economic for some time. That is still largely the case, despite the likely development of Project Aqua. Trustpower is also currently investigating a 100MW hydro scheme on the Wairau River in the South Island. This scheme is potentially attractive as it could provide irrigation for the Marlborough region in addition to electricity.

Other large-scale hydro developments are likely to be uneconomic unless prices approaching 10c/kWh can be achieved.¹⁷

A number of enhancements to existing hydro stations and small-scale distributed hydro options are either planned or considered likely. We understand that a number of these are being considered in response to the need for new capacity. Our understanding of the potential supply from small-scale hydro schemes is illustrated in Figure 4, which combines all schemes into a potential supply curve.¹⁸

Full size image of Figure 4 available.

Figure 4 demonstrates that, although there are a large number of potential small hydro projects, they tend to be expensive and the total capacity of all projects combined is still only comparable to one or two large hydro schemes.

For the purpose of our long-term supply and demand projections, we have summarised our assessment of potential hydro developments (including small-scale) in order of long run unit cost in Table 4. We observe that long lead times can be expected for many hydro projects, given the resource management act process for securing consents to build and operate hydro schemes. This tends to impose significant technical and environmental assessment, and legal and consultation costs, before a decision to proceed can be taken. Large-scale projects typically involve four to six years of construction time.

6.5 Wind Development Options

Wind energy currently provides a small contribution to New Zealand's electricity requirements. As a result of comparatively low electricity prices investment has been limited to two small wind farms in the lower North Island. More recently, exchange rate movements and rising electricity prices have combined to make investments, at least at higher quality wind sites, more attractive. Government policy to encourage renewable supply technologies such as wind has also helped improve viability.

Although resource consents have been difficult to achieve, the current policy environment and increasingly attractive economics are likely to see a renewed focus on wind farm projects. Trustpower and Meridian Energy, for example, have recently committed to 36 MW and 85 MW wind farms following agreement with government on access to carbon credits projected to accrue to New Zealand in the Kyoto Commitment period 2008 - 2012.

A large number of potential wind development options have now been well researched and documented in New Zealand.¹⁹Table 5 summarises the assessment of potential wind generation developments.

Subject to resource consent difficulties, lead-times for constructing wind farms are relatively short, of the order of 12 to 18 months.

6.6 Geothermal Development Options

Geothermal electricity generation has been a feature of New Zealand's supply system. Development has been focussed on a large high temperature geothermal resource located mostly in the Taupo Volcanic Zone, and a much smaller resource at Ngawha in Northland. Estimates have put the total high temperature resource at between 3,000 to 5,700 MW for power generation as outlined in Table 6.²⁰ Although significant parts of this resource are likely to be available for development, some fields are likely to be designated as "protected" and may prove more difficult to develop.²¹

Geothermal development offers many advantages. Power plants run as essentially base-load with a high degree of reliability and with low greenhouse gas emissions. However, development of this resource has been limited due to a number of factors including environmental issues, field risks and electricity prices.

Rising electricity prices are now making geothermal options more attractive. A range of sources²² have suggested that 200-250MW of extensions to existing projects could be commissioned over the next ten years. MED estimates,²³ in particular, have also suggested that around 600MW of geothermal generation potential could be developed over the next 25 years at prices of 6.2c/kWh. We have incorporated the commercial, technical and resource consent risks of developing geothermal fields for power generation by assuming slightly higher unit costs. In addition to the planned developments listed in Table 6 below, we have assumed an additional 230MW geothermal power development is economic at prices between 6 and 8c/kWh.

6.7 Thermal Development Options

The availability of relatively cheap Maui gas has focussed recent development of thermal power stations on gas-fired thermal combined cycle gas turbine (CCGT) technology. The development of the Southdown, TCC and Otahuhu B plants has been underpinned by contracts for supply of gas from Maui.

Gas supplies are likely to be significantly constrained as the Maui field declines through the next few years. Although new fields are being developed, it appears that gas supplies will restrict the development of further CCGT capacity.

Genesis Power has proposed a CCGT plant at its existing Huntly site, has secured the necessary resource consents and identified a preferred manufacturer. Delays in Pohokura gas coming on stream and technical risks with developing Kupe gas reserves suggest that the Genesis CCGT project, (known as e3p) is unlikely to be commissioned before 2006.

New Zealand has large reserves of coal available, some of which offer relatively cheap costs of extraction and could support coal-fired power stations at projected electricity prices. Particular opportunities exist for bitumous coal on the West Coast of the South Island and for lignite coal in Southland. Electricity prices at these locations, particularly in Southland, will typically be lower than in the central and upper North Island, however relatively cheap coal supplies may offset this disadvantage.

We have assessed the likely long run unit cost of thermal generation options including the possibility that integrated coal gasification (IGCC) technology will be commercialised within the forecast period. There have also been suggestions that Marsden B could be converted into a coal-fired station burning South Island West Coast coal or imported coal. There are significant uncertainties over these generation options and associated capital costs and we have no detailed information on the options. We have therefore excluded these options from our analysis. However we note that they may be competitive with other coal-fired options.

Table 7 shows our assessment of thermal plant economics with a $15 per tonne carbon tax.²⁴

6.8 Cogeneration

A number of other generation technologies are either in service or are likely to be built in the medium term in New Zealand. In particular, a number of cogeneration plants, mostly gas fired, have been commissioned over the last ten years. These tend to be relatively small with the larger projects having electricity export capabilities of the order of 20MW to 30MW.

There is undoubtedly more potential for cogeneration in New Zealand. In particular, there is potential for coal and biomass based plants.²⁵ However, while the economics of cogeneration options appear relatively attractive on initial analysis, some host sites have suffered from commercial and or technical problems creating general resistance to cogeneration as a result. Rising electricity prices and ongoing security of supply concerns in New Zealand are likely to see a modest number of cogeneration developments proceed. We have allowed up to 200MW over the forecast horizon.

6.9 Summary

The assessment of likely development options, in addition to those committed or "highly likely", in the period to 2020 has been summarised and established in a "merit order" of supply options in Table 8.

This table has been used to establish likely power station commissioning schedules for the With and Without Aqua scenarios.

¹²For example, Meridian Energy and Trustpower have successfully negotiated arrangements with Government so that wind farm projects achieve breakeven status in 2004. These arrangements involve access to a portion of the carbon credits projected to accrue to New Zealand from reduced CO₂ emissions from thermal power stations relating to each wind farm project during the initial Kyoto commitment period (2008 and 2012).

¹³As an example, geothermal reserves can be difficult to assess reliably with consequent uncertainty over development and ongoing production costs. For example, Ohaaki power station production fell to around half of its economic design capacity shortly after commissioning around 1990 and in spite of considerable expense since then it now operates at about half its design capacity.

¹⁴The WACC of a firm is the return required by that firm's equity and debt investors for accepting the level of risk associated with the assets of that firm.

¹⁵Short report on cost of capital to MED; Castalia, 9 February 2004.

¹⁶Energy Link has used a detailed model of the New Zealand electricity network to estimate location factors.

¹⁷Refer to Taupo Waikato Resource Consents Application and Assessment of Environmental Effects by Mighty River Power

¹⁸The data has largely been sourced from a report published by the Ministry for the Environment with our own assessment of long run unit costs.

¹⁹Refer to Review of New Zealand's Wind Energy Potential to 2015 by EECA and Availabilities and Costs of Renewable Sources of Energy for Generating Electricity and Heat for MED by East Harbour Management Services Ltd

²⁰Refer to New Zealand's Geothermal Resource (2001) by Lawless & Lovelock

²¹For example, Environment Waikato's Regional Plan proposes restrictions to field development that could curtail development of those labelled possible "protected" status in Table 6.

²²Refer to NZGA's Submission on 2001 Post Winter Electricity Review

²³Refer to New Zealand Energy Outlook to 2025 by MED

²⁴We have drawn on a wide range of sources in deriving our unit costs of thermal plants. These include Energy Information Administration (USA) Annual Energy Outlook, manufacturer websites, Solid Energy Annual Report, Gas Turbine World Handbook and US Department of Energy Office of Fossil Energy.

²⁵Coal and biomass potential given our estimates of likely fuel availability and costs, and capital costs of cogeneration. We have drawn on a range of sources for information on fuel and capital costs of cogeneration including Solid Energy Annual Report and Energy Information Administration (USA) Annual Energy Outlook.