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Electricity Commission SOO Scenario Analysis – Discount Rates 1. Introduction The Electricity Commission is developing a Statement of Opportunities to meet the requirements outlined in Part F of the Rules. As part of this process it is proposing future generation scenarios for the purpose of testing the adequacy of the transmission system under a range of possible futures. Testing the adequacy of the transmission system using these scenarios is intended to highlight opportunities for investment in transmission and alternatives to transmission. This approach involves the use of discount rates for at least two purposes, including; discounting cash flows to calculate the “unit cost” of power from particular power stations, and discounting cash flows to establish “optimised” power station commissioning schedules. This note suggests discount rates to use in applying this approach. 2. Scenario Planning Approach In order to develop the generation scenarios the Commission is evaluating a range of generation project options appropriate to each scenario. Each scenario is built up using an electricity supply/demand energy balance model (GEM) developed specifically for this task. New power stations are scheduled in the model to meet demand as it increases in the scenario. The concept involves drawing power stations from a catalogue of options designed for that scenario, starting with the lowest cost options first. This approach is intended to mimic the development of new power stations by commercial players in a market environment. Given a catalogue of future generation options available to the commercial players in the sector, the likely future supply pattern can be inferred by finding which generation options first become profitable as prices rise. This is a relatively straight-forward modelling exercise although there are some complexities in forecasting how commercial behaviour in the wholesale market will interact with the profitability of generation options that have different roles in the merit order. To establish which generation options would become profitable as prices rise the approach involves calculating a “unit cost” for each option. This unit cost is calculated by amortising the capital costs over the life of the power station, and estimating the fuel, operating and maintenance costs. These costs are spread over the expected output of the power station, making certain assumptions about the likely station operating patterns. In this way a unit cost is assessed in cents per unit (kWh) for each power station option and a “supply curve” of generation options is developed. 3. Applying Discount Rates As closely as possible, this forecasting exercise should mimic how the commercial players will assess their investment opportunities. In particular, it should make realistic allowances for the costs of capital facing the companies involved and the risks of the projects. These factors should be taken into account in assessing the unit cost of each power station option. Section 4 of this note addresses this question. The approach to developing the scenarios also involves using GEM to simulate supply and demand over 30 years, calculate capital, fuel, operating and maintenance costs, and to estimate the cost of any shortages of supply that might eventuate during dry periods. The aim is to develop a schedule of new power stations that mimics the likely market outcomes by seeking to minimise the overall NPV cost. A suggested approach for discounting these cash flows is addressed in section 5. 4. Cost of Capital for Project Unit Costs The calculation of unit costs in the SOO scenario project is intended for ranking projects and reaching 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 when discounting cash flows using the investor Weighted Average Cost of Capital (WACC). Some will factor explicit risks into project evaluations and some will assess projects using a hurdle rate of return that is higher than the firm’s WACC. 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 of the unit cost of power from projects for the SOO scenarios it should be 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. Asset pricing models like the Capital Asset Pricing Model (CAPM) give an indication of likely investor WACC. This note assesses the WACC for firms likely to invest in the electricity sector using the Brennan-Lally1 simplified version of CAPM. The range of plausible input assumptions that has been derived, and the calculation of WACC is outlined in Table 1. 1 Reference Lally 1992 2 Table 1: WACC Calculation CAPM Calculation Low Med High Risk Free Rate Debt Margin Tax Rate Leverage Asset beta Market risk premium Equity Beta Cost of debt Cost of equity Nominal WACC Rf p Tc L Ba MRP Be Kd Ke WACCn 5.6% 1.0% 33.0% 35.0% 0.50 7.0% 0.77 6.6% 9.1% 7.5% 6.0% 1.3% 33.0% 40.0% 0.60 7.5% 1.00 7.3% 11.5% 8.9% 6.4% 1.6% 33.0% 45.0% 0.70 8.0% 1.27 8.0% 14.5% 10.4% Inflation Real post-tax WACC WACCr 2.5% 4.9% 2.5% 6.2% 2.5% 7.7% This suggests a relatively wide plausible range of between 4.9% and 7.7% per annum (post-tax real) for firms operating in the electricity sector. It is relatively difficult to benchmark these calculations against investor perceptions about WACC because most firms regard cost of capital and internal project hurdle rates as confidential. This is made more difficult because, as a result of barriers to entry into generation by newcomers, most of the potential investors are SOEs and their investment thresholds are less observable than private participants. Nevertheless, there are estimates of WACC for Contact Energy and Trustpower that have been made by investment advisors and other parties. These are outlined in Table 2. Table 2: WACC Estimates for Private Generators Company WACCn Estimated by Date Contact Energy 8.8% Cameron Partners October 2004 Contact Energy 8.5% – 9.0% Grant Samuel September 2004 Contact Energy 8.8% Pricewaterhousecoopers March 2006 Trustpower 8.9% Alliant Energy May 2006 Trustpower 9.3% Pricewaterhousecoopers March 2006 These estimates are in good agreement and tend to confirm values for nominal WACC in the range between the mid-point and the high end of the calculations provided in Table 1. This is not surprising because the investment advisors tend to use similar versions of CAPM to derive WACC for individual firms. Ideally, the evaluations underlying the development of a supply curve of generation options would allow for option values or the firms’ incomplete diversification of project risks. These adjustments are not feasible in modelling the whole supply curve, and 3 instead it is necessary to apply some sort of mark-up to the estimated WACC. Indeed, this appears to be what many firms do in practice in investment appraisal. For the SOO scenario analysis it is therefore proposed to calculate power station unit costs using a discount rate towards the upper end of the plausible range of WACC for generation investors. This approach should allow most investors a positive NPV from a proposed investment. A rate of 7.7% per annum for discounting real post-tax cash flows is recommended. The model used to calculate the unit cost of different generation projects using this discount rate should incorporate tax effects including the impact of depreciation on tax. 5. Discounting Cash Flows to Determine Generation Scenarios The approach to developing the generation scenarios involves using GEM to simulate supply and demand over 30 years, calculate capital, fuel, operating and maintenance costs, and to estimate the cost of any shortages of supply that might eventuate during dry periods. The aim is to develop a schedule of new power stations that mimics the likely market outcomes by seeking to minimise the overall NPV cost over the 30 year period. Ideally this would involve assessing tax effects on a project by project basis and using the same discount rate 7.7% per annum as determined in section 4 to discount real posttax cash flows. This would tend to mimic the outcomes from a series of rational market investment decisions. However, this approach could be overly complex and impractical because of the need to allow for the effects of depreciation for tax purposes on different power station projects. A simpler alternative that could provide a reasonable approximation is to gross up the effective WACC to an approximate pre-tax number and apply this rate to the pre-tax cash flows. Grossing up the discount rate in this way is not completely straight-forward because tax has a different effect on capital expenditure (which is only deductible over time) relative to operating expenditure (which is deductible in the year in which it is incurred). Calculations indicate that discounting post-tax cash flows for typical power stations at 7.7% is equivalent to using a discount rate of between 9.5% and 11.5% per annum applied to pre-tax cash flows. The wide range of pre-tax equivalent discount rates results from the difference in cash flow profiles exhibited by different power station technologies. Rather than compromise accuracy by grossing up the discount rate and applying it to pre-tax cash flows, it is proposed to undertake the NPV calculations using the same discount rate 7.7% per annum as determined in section 4 to discount real post-tax cash flows, and to calculate the impact of depreciation for each power station type. This will involve: • Deducting tax at 33% from all operating, maintenance and fuel expenditures (opex); • Calculating annual depreciation of the capital expenditure for each power station project using the appropriate diminishing values for tax purposes; 4 • Deducting 33% of the annual depreciation from the cash flows; • Applying a 7.7% per annum discount rate to all cash flows. This means that in each year the cash flow will be: Cash flow = capex + opex*.67 – dep*.33 Using this approach will best mimic how potential investors would assess their investment opportunities. 6. Depreciation Rates for power station Projects The approach proposed for discounting post-tax cash flows in both the unit cost model and for determining the “optimised” power station schedule relies on calculating the depreciation for tax purposes on a project by project basis. The appendix to this note outlines the current allowable rates of depreciation for tax purposes and how these should be applied to various generic power station projects.. 5 Appendix – Calculation of Weighted Average Depreciation for Tax Purposes for Power Station Projects Depreciation Rates Dim Val Loading Generators & turbines 9.5% 11.4% Wind generators & turbines 18.0% 21.6% Hydro structures and land 4.0% 4.8% Pipes and wells 9.5% 11.4% Electrical equipment 7.5% 9.0% Weighted Depreciation Hydro Stations Coal Stations Gas Stations Wind Stations %CV Part% %CV Part% %CV Part% 15.0% 1.7% 60.0% 6.8% 80.0% 9.1% 0.0% 75.0% 16.2% 2.0% 0.1% 2.0% 0.1% 5.0% 0.0% 80.0% 3.8% 0.0% 0.0% 5.0% 0.5% 6.0% 0.0% 38.0% 3.4% %CV 0.0% 18.0% 10.4% 1.6% 20.0% 10.8% Geothermal Stations Part% %CV Part% 0.0% 35.0% 4.0% 0.2% 20.0% 1.0% 0.0% 30.0% 3.4% 1.8% 15.0% 1.4% 0.0% 18.2% 9.7% Note that: 1. Dim Val is the annual rate of deprecation for tax purposes allowed by Inland Revenue 2. Loading includes the 20% depreciation loading applied to new assets 3. %CV is the estimated proportion of capital value allocated to a particular depreciation category 4. Part% is the calculated contribution to the weighted depreciation for a particular category of equipment 5. Weighted Depreciation is the calculation of the depreciation rate that should be applied to the generic power station type 6