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• Appendix 2

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• Final Report
• Terms of Reference
• Model Scoping Report
• Project Aqua
• Media Statements

• Introduction
• Generation Capital Expenditure
• Transmission Capital Expenditure
• Reserve Capital Expenditure
• Operation and Maintenance Costs
• Fuel and Emissions Costs
• Residual Value of Annual Costs

Introduction

In order to evaluate the impact of Project Aqua on the electricity sector, we adopted the approach outlined in section 4 of the report. This involved establishing the difference in cash flows across the period to 2020 between the two scenarios and calculating the net present value of that difference.

Because we are attempting to quantify the net national benefit of Project Aqua to the electricity sector, we have ignored tax effects in this part of the analysis and discounted the cash flows using the traditional public sector discount rate (PSDR) of 10% per annum. We have also tested the sensitivity of the conclusions to a 7.5% PSDR and a 5% PSDR.

Generation Capital Expenditure

In order to establish the cash flow difference in capital expenditure on generation investments we have determined a generation capital cash flow for each scenario. This cash flow focuses on areas of difference between the two scenarios and ignores investment in projects that are common in timing between the two scenarios. Table A-2 outlines the key differences in investment in new power station MW between the two scenarios.

In order to establish the capital expenditure differences we have used the parameters outlined in section 6 of the report which are summarised in Table A-3.

In order to simplify the analysis we have adopted a convention of incurring capital expenditure at the beginning of the calendar year prior to the year in which electricity generation is achieved. The resulting generation capital expenditures are outlined in Table A-4 for each scenario.

The difference between the capital expenditure profiles in Table A-4 appears in Table 11 of the report.

By 2020, the power station assets and the economic lives of those assets vary between the scenarios. The value of this difference needs to be taken into account in the discounted cash flow. In order to do this, we have calculated a residual value for the assets in each scenario by estimating economic lives and developing a forecast capital expenditure program that maintains a similar mix of plant available to meet demand right through to the end of Project Aquas economic life.

The difference in residual value between the two scenarios appears as the generation residual value difference in Table 11 in the report.

Transmission Capital Expenditure

To establish the difference in capital expenditure on transmission between the two scenarios we have assumed that:

• all regional transmission costs associated with generation projects are included in the power station capital expenditure;
• AC transmission core gird development will proceed to a similar timeframe and cost under both scenarios;
• the only potential difference between the scenarios is likely to relate to an additional cable associated with HVDC refurbishment as outlined in section 8 of the report.

We have therefore included a cost of $80m in 2010 in the With Aqua scenario. We consider that it is likely that an additional cable would be also economic at some point in the Without Aqua scenario. We have therefore included an $80m cost in 2015, coinciding with the development of potential coal fired power stations in the South Island. A residual value associated with the difference in the economic life of the new cable in 2020 is also included in this analysis.

Reserve Capital Expenditure

For our central analysis we have not included a penalty on Project Aqua for security of supply. The reasons for this are outlined in section 9 of the report. However, as sensitivity, we have evaluated the possible impact on the analysis of adding a reserve plant in the With Aqua scenario.

In order to establish a possible size and cost of the reserve plant for this sensitivity we have observed that Project Aqua will add to the annual variability of hydro production, arguably creating a need for more reserve plant. We have simulated hydro generation in both scenarios and estimated the increase in variability of hydro production as between 4% and 12% (depending whether variability is considered on a South Island or NZ basis).

The Electricity Commission has been tasked with providing up to 1200 GWh pa in reserve energy over a four month period during the winter. This is equivalent to 400MW of thermal power station capacity. It is not clear how the Electricity Commission might address any perceived need for additional reserve capacity. In order to establish a reasonable sensitivity on reserve costs, we have adopted a relatively simple assumption that the Electricity Commission may elect to provide an additional 12% (or 48MW) of reserve capacity. We have evaluated this as open cycle gas turbine plant required in 2010 at a cost of $1,000 per kW.³² We have assumed that the plant would be held in reserve and actual running time would be negligible.

Operation and Maintenance Costs

A combination of different power station types in the two scenarios suggests that annual costs of operation and maintenance could differ between the scenarios. We have therefore calculated the annual difference in these costs using the capacity differences outlined in Table A-2 of this appendix and the operations and maintenance costs outlined in Table A-5.

Fuel and Emissions Costs

The fuel and emission costs have been calculated by establishing the generation differences between the scenarios for all thermal power stations.³³ These have been valued using the thermal fuel price, emission price, and emission rate assumptions outlined in section 5.

The additional transmission losses calculated for the With Aqua scenario have been supplied by additional thermal power station running, with consequent impact on fuel and emission costs.

The average generation differences (averaged across 20 hydro inflow sequences) are tabulated in Table A-6.

From this table it is evident that Project Aqua is likely to lead to less running of CCGT stations on average as well as less running of Huntly on coal. It is also evident that New Plymouth is hardly running in all 20 inflow sequences across the period to 2020. Both these observations relate to the increased margin of supply over demand (relative to the existing situations) that we have maintained in both scenarios.

Residual Value of Annual Costs

It is clear from Table 11 in the report that Project Aqua leads to annual savings in the cost of fuel, carbon emissions and operations and maintenance, over the period to 2020. These savings will continue beyond 2020. The rate at which these savings will accrue will depend upon a number of factors, including the investment in new power stations beyond 2020. For this analysis, we have taken the average of the savings across the three years 2018 - 2020 as indicative of the likely level of sustainable savings over the life of Project Aqua. We have included 30 years of savings in the residual calculation to reflect the expected economic life of Aqua.

³²Slightly less than the estimated cost of the Whirinaki reserve plant.

³³These have been estimated by simulating the two scenarios for each of the 20 hydro inflow years used in this analysis and average power station outputs. Note that the Southland lignite plant and West Coast coal plants are included in this analysis.