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MERIDIAN ENERGY ` Date: 23/09/2016 Current Price: $2.85 Recommendation: BUY Ticker: MEL.NZSE Target Price: $3.16

Market Profile Executive Summary Closing Price $2.85 52-week Range $2.10-$3.05 We issue a BUY recommendation on (MEL) with a one-year target Share Outstanding 2,561,300,000 price of $3.16 which offers a 16.3% total return, including dividends, on the closing price Market Capitisation (000s) $7,304,550 of $2.85 on the 23rd of September, 2016. Our recommendation is driven by: Forward P/E 24.15 EV/Forward EBITDA 11.27 Electricity Demand Growth – Growth in 2015 national electricity demand coupled with Dividend Yield 6.67% forecasted increases in GDP and population growth provides a positive outlook for increases in future demand. As a generator MEL would benefit from the associated Source: Bloomberg, NZX, Team Estimates increase in wholesale spot prices. Recommendation Rule Current Price $ 2.85 Positive Generation Outlook – MEL is New Zealand’s largest electricity generator Market Return Assumption 8.28% producing approximately 34% of national FY2016. Large capital Sell Expected Return less outlays provide barriers to entry to the generation industry, solidifying MEL’s than -8.28% competitive position. As a predominately hydro generator MEL has the lowest short-run Hold Expected Return between -8.28% and marginal cost amongst its competitors, therefore, barring adverse hydro conditions MEL Buy Expected Return would be expected to generate cash strong flow in perpetuity. greater than 8.28% Source: Team Estimates Stable Retail Position – Despite increased retail competition, MEL has maintained a Valuation Summary consistent market share of approximately 13% and has the second lowest net switch rate Method Price Weight Weighted Price since 2012 amongst the big five gentailers. Smart meter rollout and a strong customer FCFF $3.42 0.5 $1.71 base from MEL’s brand suggest a stable retail outlook, with the firm’s retail DDM $3.37 0.25 $0.84 segment providing a natural hedge against falling wholesale prices. EV/EBITDA $2.55 0.25 $0.64 No Closure Price $3.19 Strong Cash Flows and Shareholder Return – MEL has seen growth in EBITDAF of Tiwai Risk-Adjustment -$0.03 12% in the past four years primarily driven by solid generation inflows and improving Target Price $3.16 retail performance. Dividend increases in each of the past four years and forecasted Source: Team Estimates – Further details in sustainable dividend growth signals continued high shareholder return. Appendix G Bull and Bear Scenario Analysis Valuation – Our target price of $3.16 per share was obtained using a combination of FCFF, DDM and Relative Valuation analysis, as well as incorporating a 10% possibility Bull Case Price Weight Weighted Price of a Tiwai closure. FCFF $ 3.54 0.5 $ 1.77 DDM $ 3.37 0.25 $ 0.84 Investment Risks – New Zealand Aluminium Smelters (NZAS) closure and adverse EV/Fwd EBITDA $ 2.57 0.25 $ 0.64 hydrological conditions remain the two largest risks to MEL’s short to medium-term Target Price $ 3.26 earnings. Additional risks to MEL are: power station production risk, and regulated Bear Case Price Probability Weighted Price market structure changes in both New Zealand and Australia. 2019 Closure $ 2.89 0.5 $ 1.45 2020 Closure $ 2.94 0.3 $ 0.88 Bear and Bull Case – We also consider a best and worst case scenario for MEL, in 2022 Closure $ 3.01 0.2 $ 0.60 addition to our base valuation. Our bear case presumes a 100% probability of a Tiwai Target Price $ 2.93 closure, reducing our target price to $2.93. A Tiwai closure is incorporated into our base Source: Team Estimates case with a 10% probability of closure weighting. Our bull case presumes a 0% probability of a Tiwai closure as well as allowing retail prices to rise by 2% per year, Share Price Movement assuming retail competition would fall with rising wholesale prices squeezing profit 7500 $3.50 margins of pure retailers. This scenario produces a target price of $3.26. 7000 $3.00 Key Financials and Ratios: No Closure Scenario 6500 $2.50 As at 30/6 2015 2016 2017F 2018F 2019F 2020F 2021F 6000 $2.00 Total Energy Margin $ 954 $ 1,009 $ 1,104 $ 1,082 $ 1,105 $ 1,163 $ 1,185 5500 $1.50 Total EBITDAF $ 618 $ 650 $ 743 $ 714 $ 768 $ 846 $ 863 5000 $1.00 NPAT $ 247 $ 185 $ 302 $ 280 $ 315 $ 361 $ 363 4500 $0.50 Debt to Equity 23.8% 25.0% 26.5% 28.4% 31.1% 35.6% 36.4%

Return on Equity 5.2% 3.6% 6.2% 5.9% 7.0% 8.3% 8.6%

11/15 03/14 08/14 01/15 06/15 04/16 10/13 EBITDAF per Share $ 0.24 $ 0.25 $ 0.29 $ 0.28 $ 0.30 $ 0.33 $ 0.34 NZX50 MEL Payout Ratio 1.56 2.72 1.62 1.79 1.62 1.47 1.21 Dividend per Share $ 0.15 $ 0.20 $ 0.19 $ 0.20 $ 0.20 $ 0.21 $ 0.17 Source: Bloomberg Source: Company Data, Team Estimates

Figure 1. MEL’s percentage of NZ Business Description Total Generation Meridian Energy Limited (MEL.NZSE) is a majority state-owned, vertically integrated electricity generator and retailer. MEL began operations in 1999 with the breakup of the 35.00% 33.8% 33.2% 33.0% Electricity Corporation of New Zealand (ECNZ) into three separate businessesi as the New Zealand electricity market began deregulation. In October 2013, MEL was publicly 30.5% listed on the NZX and ASX, with The Crown retaining 51.02% ownershipii. 30.00% With the breakup of the ECNZ, MEL was granted control over the Waitaki hydro scheme 27.2% and the Manapouri hydro station, both of which are located in the central South Island. Currently, MEL owns and operates seven hydro stations in the lower South Island, five 25.00% wind farms throughout New Zealand and two wind farms in Australia. Accounting for approximately 34% of total generation FY2016, the firm is New Zealand’s largest electricity generator. (Figure 1). As a predominately hydro generator MEL benefits from 20.00% a low-cost structure relative to its competitors dependent on higher cost thermal. Wind 2012 2013 2014 2015 2016 generation provides some protection against adverse hydrological conditions, however, Source: Energy Link MEL’s earnings can be volatile due to its dependence on consistent levels of rainfall and snowmelt.

Figure 2. Segment Proportion of MEL’s operations can be broken down into several segments: NZ generation; which NZ Contracted Sales (GWh) comprises the sale of the firms hydro and wind generation into the spot market; NZ wholesale contracted sales, encompassing sales to the New Zealand Aluminium Smelter (NZAS) and net derivative contract sales; NZ retail contracted sales; and International th 10% generation and contracted sales. As at 30 of June 2016, the NZAS accounts for 41% of MEL’s NZ total contracted sales volume and consumes between 13-15% of national generation annually (Figure 2). Weak global aluminium prices and a strong New Zealand 49% dollar have decreased the profitability of the smelter, threatening its viability. As the smelter comprises such a large proportion of MEL’s contracted sales and NZ generation 41% as a whole, its failure is a key risk to the generation industry.

Company Strategy MEL’s company strategy is to operate as an efficient, vertically integrated electricity generation and retail companyiii.

Total Retail NZAS Financial Contracts  Vertical integration – Operating as a vertically integrated business provides a natural hedge against periods of high wholesale prices which are typically Source: Company Data, Team associated with low hydro levels as decreasing retail margins are countered with Estimates increases in generation prices. This gives MEL a competitive advantage over pure retailers who face declining overall margins in times of increasing wholesale prices. Figure 3. MEL Dividend Payout  Shareholder return – With a period of flat electricity demand and low short-term growth opportunities MEL has committed to returning a high proportion of cash flow to shareholders over the next several years. FY2016 MEL declared an ordinary 20.00 dividend of 13.50cps with a special dividend of 4.88cps (Figure 3). This represents 18.00 a 5% growth in ordinary dividends for the past year and a 33% total shareholder return compared with 20% return in the NZX top 50 companiesiv. 16.00 5.35 4.88  – MEL generates 100% of its electricity from renewable 14.00 sources, benefiting from a combination of hydro stations and wind farms. While 12.00 2.00 both wind and hydro generators are heavily reliant on weather conditions they 10.00 provide MEL with lower operating costs than thermal and geothermal generators 8.08 8.40 v 8.00 and have long operating lives . Additionally, this aligns MEL with the government’s 6.82 goal of 90% renewable electricity generation by 2025 and provides the firm a 6.00 reputational advantage over fossil fuel reliant companies. 4.00 Shareholder Structure 2.00 4.19 4.80 5.10 MEL is a mixed-ownership, majority state-owned enterprise with The Crown owning 0.00 51.02% of total shares outstanding and all minority owners restricted to a maximum 10% 2014 2015 2016 ownership interest. Institutions and individual investors own the remaining stake in the firm, with National Nominee New Zealand Limited recording the next largest ownership Interim Final Special stake at 4.89% as at 30 June, 2016 (Figure 4). Source: Company Data

Figure 4. Shareholder Structure Corporate Governance As at June, 30, 2016 MEL adheres to best practice policy as outlined by the NZX and ASX best practice code and has a well-established and effective board committee structure which includes: an 21% Audit and Risk Committee; Remuneration and Human Resources Committee; Governance and Nominations Committee; and a Safety and Sustainability Committee. We believe the internal and external audit function ensures transparency of financial 51%, reporting for shareholders. 28% The board is wholly comprised of independent directors, and is in accordance with MEL’s outlined gender diversity targetsvi. The directors provide a range of industry and business expertise with directorship tenure with MEL ranging between four-eight yearsvii. Board The Crown Registered Institutional Other compensation is competitive and consistent with the industry average salary for Source: Company Data directorship (Figure 5). Director and executive performance is evaluated by the Remuneration and Human Resources committee, with an independent review of board Figure 5. Average Director’s performance taking place in 2015 supporting their effectivenessviii. We find the move to Compensation ($000s) ix 120 a more equity based LTI plan an encouraging signal for aligning investor goals with those of management (Table 1). 100 MEL’s CEO, Mark Binns, was appointed in January 2012 following his role as CEO of 80 the infrastructure division of Limited. Under his tenure as CEO, MEL 60 has undergone an IPO which has seen a 90% share appreciation and an increase in ordinary dividends from 11.01cps to 13.50cps. Further, solid financial performance has 40 seen EBITDAF grow at 3.57% p.a. in his three years at the helm. For these reasons we 20 view Mark Binns as a capable leader for MEL for the foreseeable future.

0 The primary concern regarding mixed-ownership, majority state-owned enterprises is the rights of minority shareholders. We believe that the rights of minority shareholder are upheld as MEL complies with all four levels of the IFC-World Bank matrix for Shareholder Rights (Appendix B). Additionally, New Zealand ranks number one in Asia- Company total Industry Average Pacific for minority shareholder rights in the World Banks 2016 ‘doing business’ reportx. Source: Company Data, Team Our analysis following the ISS rating methodology indicates current management are Estimates likely to act in the best interest of shareholders (Appendix C). Table 1. Equity-Based Share-Payments ($M) Industry Overview and Competitive Positioning 2013 2014 2015 2016 - 0.4 0.9 1.4 Industry Overview

Source: Company Data The electricity sector comprises five key participants. Generators produce electricity which is directly sold to the wholesale spot market. All electricity produced is transmitted from electricity generators on either the HVDC or HVAC to the state-owned national grid operated by Transpower. Distribution networks then transmit the electricity from the Figure 6. Percentage of Total New national grid on behalf of the retailers who purchase electricity directly from the Zealand Generation by Energy wholesale spot market to fulfil customer contracts. Source, FY2016 Generation Large initial capital outlays create high barriers to entry in electricity generation with the 17% sector currently dominated by the five publicly listed companies. Renewable energy accounted for approximately 82% of total national generation FY2016, with hydro as the largest individual generation source, producing 60% of national generation (Figure 6). The relative importance of hydro generation to the sector leaves it susceptible to adverse 23% 60% weather conditions such as low rainfall or snowmelt levels, with dry periods reducing supply to the wholesale market creating volatility in wholesale prices. April 2016 saw an agreement reached between Genesis and MEL to push back the closure of the Huntly Rankine units, a thermal producer, until 2022 to counter volatile wholesale prices, particularly in times of peak demandxi.

Hydro Other Renewable The industry has seen flat electricity demand between 2006-2013, with small increases Non-Renewable in FY2014 and FY2015. Despite this, significant capital expenditure on renewable energy generation has taken place. The increase in renewable energy generation capacity has Source: Energy Link, Team Estimates raised concerns of a potential short-term oversupply and has put financial pressure on the higher cost-structure thermal generators, leading to the closure of the Southdown and

Figure 7. Previous Five-Year Otahuhu B thermal plantsxii. The closure of these units demonstrates the governments Aluminium Prices vs. NZD/USD focus on the generation mix of electricity producers, with a national target of 90% renewable energy by 2025xiii. $3,000 $0.90 Tiwai $2,500 $0.80 The NZAS accounts for approximately 13%-15% of annual total electricity demandxiv. A period of a historically high NZD/USD coupled with weak global aluminium prices has $2,000 $0.70 lowered the profitability of the aluminium smelter and raised concerns in the electricity industry surrounding its continued operation (Figure 7). NZAS is currently contracted to $1,500 $0.60 MEL for 5,011GWh p.a. and has the right to terminate the contract with 12 months’ notice as of January 1, 2017. Due to the amount of electricity the smelter consumes, the failure $1,000 $0.50

of the plant would lead to a short-term oversupply, and a subsequent decrease in

2011 2013 2014 2015 2016 2012 wholesale prices and earnings for electricity generators.

ALMN (USD) NZD/USD Retail Market The Electricity Industry Reform Act 1998, was enacted to increase competition between Source: Bloomberg electricity retailersxv, causing the number of retailers and average customer switch rate to increase steadily since (Figure 8). Despite increased competition in the retail sector, Figure 8. Retailer Growth vs. market share has remained relatively stable for four of the five gentailers with only Number of Switches seeing a significant decline. Outside of the five largest companies, Todd 445000 25 Energy and Pulse energy are the companies with the largest increases in market share.

420000 20 The five largest retailers in the sector are vertically integrated businesses with both 395000 15 generation and retail businesses. Vertical integration provides a natural hedge against volatile wholesale prices as decreases in retail energy margins in times of high wholesale 370000 10 prices are offset by increases in generation energy margins. Unlike the vertically 345000 5 integrated companies in the sector, pure retailers are vulnerable to volatile wholesale prices and have seen high dropout rates. 320000 0

Demand Drivers

2011 2012 2013 2014 2015 2016 2010 Demand for electricity in New Zealand typically follows various macroeconomic factors Retailers Switches and seasonal conditions (Appendix D). Source: Electricity Authority  GDP and Population Growth – Increases in GDP and population growth are generally associated with increases in electricity demand. However, this relationship Figure 9. Electricity Demand (PJ) has broken down in recent years with electricity demand flat and average residential 145 consumption declining despite annual GDP growth averaging 2.5% and population increasing 6.1% since year end 2011 (Figure 9 & 10). This change in the electricity demand profile is not viewed as a structural change by the Electricity Authorityxvi 130 and with increases in both long-term GDP and population forecastedxvii the outlook for national electricity demand appears positive. 115  Weather – Seasonal conditions represent a significant factor in electricity demand with annual electricity demand typically higher in winter. A large agricultural 100 industry, particularly in the lower to Mid-South Island, drives demand in low rainfall periods through increased irrigation loads. These factors can cause volatility in earnings for hydro generators such as MEL as high demand in dry periods increases Source: Electricity Authority the volume electricity suppliers have to purchase from the wholesale market at higher prices. Figure 10. Quarterly GDP and  Substitutes – Natural gas is the closest substitutes for electricity in New Zealand, Population growth (%) with a network of high pressure lines throughout the North Island. This causes price 0.16 0.007 changes in natural gas to affect the demand for electricity, with lower gas prices 0.006 0.13 reducing electricity consumption. In addition to gas, increasing solar panel 0.11 0.005 installation in homes has the potential to reduce electricity demand over time as 0.08 0.004 panels become more economically viable. 0.06 0.003 International Market 0.002 0.03 The Australian NEM is conducted through a wholesale market, similar to that of New 0.01 0.001 Zealandxviii. However, in contrast to New Zealand, the generation mix is largely fossil -0.02 0 fuelled based thermal generation. In an effort to encourage renewable energy the Gillard- led Australian government introduced a carbon price which increased the price of carbon emissions for Australia’s 300 highest emitters. This carbon price was subsequently GDP Growth Population growth repealed by the Abbott-led government on July, 17th 2014. Continued political Source: Economics, Statistics New Zealand

Figure 11. Energy from Renewable uncertainty regarding commitment to RET’s has left sustainability of long-term vs. Non-Renewable (GWh) FY2016 renewable energy generation in Australia unclear. 14000 Competitive Positioning 12000 10000 Favourable Generation Position 8000 MEL has an established line of wind farms and hydro generation plants in the North and 6000 South Island and is the largest generator in New Zealand producing 34% of total 4000 electricity FY2016. Hydro, which makes up approximately 90% of MEL’s generation, has a low marginal costxix giving MEL a cost advantage over its competitors using 2000 thermal. Due to this low short-run marginal cost MEL is expected to produce strong cash 0 flow barring adverse hydro conditions. Additionally, upon review by the EA in 2015, the CEN GNE MCY MEL TPW current TPM was deemed to have allocated a disproportionate share of costs to South Renewable Non-Renewable Island generatorsxx. The proposed changes to the TPM would see MEL save an estimated Source: Company Data $57M p.a. from April, 2019, reducing their cost of production. Further, Government Figure 12. Retail Market Share targets of 90% of total energy from renewable resources by 2025 provide MEL, as a 100% 5-Year Comparison renewable energy generator, with a strong competitive outlook relative to its competitors 30% more reliant on non-renewable resources (Figure 11).

25% Stable Retail Outlook 20% Despite increased competition in the retail sector MEL has maintained a stable market share over the past five years (Figure 12). This competitive retail market causes customers 15% to be highly price sensitive, as evidenced by the increase in switching rates over the past 10% five years (Figure 8). MEL continues to compete on price with an average retail price 5% currently in the bottom two-thirds of the industry and a stated intention to remain within this bandxxi. 0% CEN GNE MCY MEL TPW MEL’s vertically integrated business structure gives the firm advantage over pure 2011 2016 retailers as it provides a natural hedge against volatile wholesale prices. This coupled Source: Electricity Authority with a market nearing full saturation provides MEL with a relatively stable market share Figure 13. Porter Five Forces outlook in the short to medium-term. Analysis – Generation and Retail Infrastructure Developments and Powershop Threat of New The current retail market landscape has shifted MEL’s focus to improving the overall Entrants 5 customer experience through the development of infrastructure. The rollout of smart 4 meters has been a key objective of MEL, with a target of having 90% of its customers 3 using the devices by March, 2017. Smart-meters paired with the development of MEL’s Competitive 2 Threat Of Rivalry 1 Substitutes online platform enables customers to monitor usage patterns and improves MEL’s overall 0 internal efficiency.

MEL’s wholly owned subsidiary, Powershop, recently won the Canstar Blue 2016 most xxii Supplier Buyer satisfied customers award for electricity providers making it a fifth year in a row . The Power Power Powershop service allows customers to buy prepaid ‘electricity packs’ online creating a Generation Retail level of product differentiation in the retail sector which we view as a competitive Legend advantage for MEL. 0 - No threat to the Business 5 - High threat to the Business Source: Team Estimates (Appendix E) Investment Summary Table 2. Valuation Summary We issue a BUY recommendation on MEL with a 12 month target price of $3.16. This Method Price Weight Weighted Price price appreciation, combined with a forecasted FY2017 dividend of $0.19 per share FCFF $ 3.42 0.5 $ 1.71 provides a total return to investors of 16.3% from the firm’s closing price of $2.85 as at DDM $ 3.37 0.25 $ 0.84 September 23rd 2016, relative to an expected market return of 8.28%. We arrived at this EV/EBITDA $ 2.55 0.25 $ 0.64 price using a combination of FCFF, DDM, and Market Multiple analysis as well as having No Closure Price $ 3.19 incorporated a 10% probability of a Tiwai closure. This recommendation is supported by Price Prob Weighted Price several factors driving value: No Closure $ 3.19 90% $ 2.87 2019 Closure $ 2.89 5% $ 0.14 Strong Cash Flow Growth Driven by Generation 2020 Closure $ 2.94 3% $ 0.09 Being New Zealand’s largest generator in an industry with high barriers to entry provides 2022 Closure $ 3.01 2% $ 0.06 MEL with a secure competitive position. MEL’s large generation segment levers the firm Target Price $ 3.16 towards increases in wholesale spot prices as long as generation levels are maintained. The Energy Link price paths utilized in our analysis suggest a significant increase in spot Source: Capital IQ, Company Data, prices over our forecast period, driving an increase in generation energy margin. Were Team Estimates

Figure 14. Annual prices to decline the firms natural hedge causes cash flow to remain relatively stable Dividends ($M) allowing the firm to maintain its value. 600 High Dividend Payout 500 Low growth prospects coupled with strong earnings and low financial leverage has

400 allowed MEL to return an increasing amount of earnings to shareholders in the form of

300 dividends. An already high ordinary dividend coupled with the firm capital management programme offers an attractive yield to investors, especially with global interest rates at 200 historic lows. We see this strong payout being maintained over the next 10 years with a 100 forecast average annual dividend growth rate of approximately 4% (Figure 14) 0 Retail Segment Providing Cash Flow Stability MEL has been able to maintain a consistent market share over the past four years, despite Capital Management Programme a highly competitive market, due to the expansion of its Powershop brand, holding the Ordinary Dividend second best net switch rate among the big five gentailers. In addition, our forecasts Source: Company Data, Team Estimates suggest solid retail demand growth of 1.2% per annum over the forecast period. While Figure 15. Tiwai Closure we have forecasted retail performance declining significantly over our forecast period Scenarios due to increasing wholesale prices, this segment is valuable in that it allows MEL to hedge $3.25 $3.20 fluctuations in spot prices, with retail earnings offsetting poor generation performance $3.15 when wholesale prices decline. $3.10 $3.05 $3.00 Tiwai Closure Remains a Concern $2.95 The potential closure of Tiwai provides significant downside risk to MEL. Figure 15 $2.90 shows the value per share were the smelter to close, with a closure decreasing the intrinsic $2.85 $2.80 value per share between 5.8%, were the smelter to close in FY2022, and 9.8%, were the $2.75 smelter to close in FY2019. While this represents a significant decline in value, we view $2.70 2019 2020 2022 No Closure the smelters closure as unlikely given the government’s demonstrated willingness to Closure Closure Closure provide both direct and indirect subsidies to the smelter as well the forward curve Source: Company Data, Team Estimates, suggesting improving aluminium prices. Energy Link – Appendix J

Table 3. FCFF Analysis Valuation FCFF Valuation We utilised a combination of FCFF, DDM and Relative valuation methods in arriving at Present Value of Firm $ 10,022 our target price of $3.16. We chose to value MEL as a whole rather than using a sum of Less Debt - 1,262 parts methodology as we feel this better captures the synergies MEL gains from operating Present Value of Equity $ 8,760 in both the generation and retail segments and better reflects the way management Shares Oustanding 2,563 measure firm performance. In arriving at our target price we also incorporated the effect Value per Share $ 3.42 a Tiwai closure in FY2019, FY2020 and FY2022 would have on MEL’s value. Source: Company Data, Team Estimates – Appendix G FCFF A free cash flow to firm analysis was used as our primary method of valuation due to MEL’s generation-retail hedge causing cash flows to remain relatively stable when key Figure 16. MEL Monthly driver assumption are altered. Using this method we calculated a value per share of $3.42. Hydro Generation (GWh) In employing a FCFF valuation we were required to make several assumptions regarding the factors driving MEL’s value as outlined below: 1800 Generation 1600 Generation Volume – A test of stationarity on historical monthly hydro and wind generation suggested both are mean reverting over the medium term (Appendix F). This 1400 motivated our use of four and two year average generation volumes, held constant over the forecast period for hydro and wind, respectively. Due to the current high South Island 1200 storage levels, we allowed a higher than average hydro generation volume FY2017 (Figure 16). 1000 Generation Weighted Average Price (GWAP) – We used average annual forecast price paths provided by Energy Link in our valuation. 800 Wholesale Tiwai Sales Volume – Due to the recent poor performance of the smelter we forecasted Source: Energy Link a drop in sales volume FY2017. However, with Aluminium forward contracts indicating an upturn in pricing over the next three years, we forecasted sales volume to begin increasing at 2% p.a. following the initial downturn.

Figure 17. Number of Tiwai Average Sales Price– The sales price to the NZAS is not disclosed, however, we Switches (ICPs) estimate the average price for total sales to the NZAS to be approximately 48 $/MWh (Appendix A). We forecasted, this price to rise with inflation as specified in the NZAS contract agreement. 20000 Derivative Contracts – Price forecasts for both buy and sell side contracts are 10000 determined by our spot price forecasts provided by Energy Link, with buy-side contract 0 prices historically 120% of those of sell side contracts. We apply the inverse growth rate of generation volume to acquired generation volume and a historically consistent growth -10000 rate to financial contracts sold. -20000 Retail -30000 Retail Sales Volume – With a saturated retail market and forecast rising wholesale prices -40000 set to squeeze the margins pure retailers we view market share remaining constant over -50000 the forecast period (Figure 17). To forecast demand growth we utilised a Vector Auto Regressive model (Figure 18) (Appendix G). Retail Average Sales Price – We forecast average retail sales prices rising with inflation over the forecasts period. The retail market for electricity is highly competitive, giving Source: EMI, NIWA, Statistics MEL little room to raise prices while remaining competitive. Additionally, MEL’s CFO New Zealand, Team Estimates has stated the firm does not plan to raise prices significantly as the firm wishes its prices to remain to the lower two-thirds of the retail market. Figure 18. Retail Average Cost to Supply Retail Sales (LWAP) – The cost to supply retail sales was Demand Growth VAR obtained by calculating an average spot price, weighted by the percentage of MEL’s 0.6 Output customers in the lower and upper-South Island, and lower-middle and upper-North Island based on number of ICP’s FY2016. This also includes a lines loss charge of 7%, in line with estimated historical estimates. 0.4 Key Costs 0.2 Transmission Expense - Recent proposed changes by the EA to the current transmission pricing would provide a $57 million cost saving to MEL in FY2019-20. It appears this 0 change is likely, therefore, we incorporated the $57 million reduction in transmission costs spread over two years into our forecast. Capital Expenditure – Capital expenditure was forecast using the firm’s stated stay-in- -0.2 business expenditure of $65m FY2017, which increases with inflation over the forecast period. In addition, we included a $250m capital expenditure spread over 2019 and 2020 -0.4 Forecast to account for MEL’s stated intention to invest in further capacity before 2023. To Lower CI estimate the production from this investment, which we presume would be a windfarm, Upper CI -0.6 we applied the GWh production per dollar invested of the Mill Creek windfarm and apply

this ratio to the $250m.

2019 2016 2017 2018 2020 2021 2022 2023 2024 2025 2026

Source: EMI, NIWA, Stats NZ, International Team Estimates – Appendix G We see growth in MEL’s Australian operation slowing over the forecast period due to the LGC forward curve indicating wholesale prices will remain relatively flat and MEL’s retail segment moving out of its growth phase, having now been exposed to the market Table 4. WACC Calculation for several years.

WACC To compute an appropriate discount rate, we estimated both a forecast period and terminal value WACC using a three month average 10Y government bond yield and a 10 year average of historical 10Y government bond yields. We believe this method provides a more accurate discount rate as the current 10Y government bond yields are historically low, misrepresenting long-term expectations. To calculate a beta we first calculated the median industry unlevered and then re-levered using MEL’s debt-to-equity ratio. Both the forecast period and terminal value cost of equity were calculated using a standard CAPM approach with a market risk premium of 6.0%. The cost of debt for both periods was calculated using the respective risk free rate plus a 275 basis point corporate bond spread with a corporate tax rate of 28%. We used a forecast period capital structure equal to MEL’s current 0.25 debt-to-equity ratio and a terminal value debt-to-equity ratio of Source: Company Data, RBNZ, Team 0.3, in line with MEL’s capital structure restrictions. Estimates – Appendix I

Terminal Value Table 5. DDM Analysis We applied a terminal growth rate of 2.3% to FY2026 NPAT before adjusting for non- Dividends cash charges to arrive at a perpetual FCFF figure. In calculating a terminal capital Stage 1 Growth Rate 3.00% expenditure figure we applied a 2.5x CAPEX multiplier to account for the significant Stage 2 Growth Rate 4.50% future capital expenditure required to maintain and develop MEL’s generation business. In discounting this value we use a long-term WACC which accounts for expected Stage 3 Growth Rate 2.30% increases in interest rates towards a long-term average. Present Value of Dividends $ 8,641 Shares Outstanding 2,563 DDM Value per Share $ 3.37 MEL has historically returned a large proportion of earnings to shareholders as dividends, Source: Company Data, Team with pay-out ratio in excess of 100% over the past three years. We forecast MEL as Estimates – Appendix H having to raise debt until 2020 to fund a consistent high dividend while completing the capital management programme. In our DDM valuation we used a three-stage growth Table 6. EV/Fwd EBITDA rate method, with a growth rate of 3% maintained until 2020 followed by a 4.5% growth Analysis rate up until 2026. This allowed MEL’s debt-to-equity ratio to fall under our long-run EV/Fwd EBITDA target of 30% by 2026. The terminal value uses our long-run growth rate of 2.3%, in line Industry Median Ratio 10.23 with forecast GDP growthxxiii. This method produced a value per share of $3.37. Meridian Fwd EBITDA $ 743.17 Market Multiple Implied EV $ 7,602 Less Net Debt -$ 1,073 We also incorporate an Enterprise Value to Forward EBITDA market multiple valuation Implied Value of Equity $ 6,529 into our analysis. This method is useful in valuing MEL as electricity generators are asset Shares Oustanding 2,563 intensive companies and, therefore, carry large non-cash depreciation charges which are Value per Share $ 2.55 excluded from performance using EBITDA. To value MEL using this method, we first found the median EV/Fwd EBITDA ratio of Meridian four primary competitors then Source: Company Data, Team apply this multiple to MEL’s one year forward EBITDA. From this we subtract net debt Estimates and divide by shares outstanding to obtain a value per share of $2.55. This is significantly Table 7. Tiwai Closure Scenario lower than our DCF methods as EV/Fwd EBITDA fails to capture earnings growth past Weighted Price FY2017. However, this method also reduces the effects of any errors inherent in our Price Probability Weighted Price assumptions, therefore, we include this in our valuation to maintain a level of No Closure $ 3.19 90% $ 2.87 conservatism in our target price. Tiwai 2019 $ 2.89 5% $ 0.14 Tiwai Closure Tiwai 2020 $ 2.94 3% $ 0.09 The final step we take in arriving at our target price is incorporating the possibility of a Tiwai 2022 $ 3.01 2% $ 0.06 Tiwai closure in FY2019, FY2020 and FY2022. The intrinsic values following a closure Target Price 3.16 in each year along with our no closure price are weighted as a probability then summed Source: Company Data, Team to arrive at our target price of $3.16. See appendix J for our full Tiwai closure analysis. Estimates, Energy Link Figure 19. Dividend Yield Financial Analysis Comparison (%) 9.00 Operational Leverage towards Rising Wholesale Prices MEL’s large generation segment levers operating performance towards rising wholesale 8.00 spot prices. In our base case using Energy Link forecast price paths we expect relatively large increases in spot prices over the next 10 years, leading to an average annual increase 7.00 in total energy margin of approximately 3%. This total energy margin increase is a 6.00 function of a 7% average annual increase in generation margin offset by weakening retail performance and increasing losses from Tiwai. This feature of MEL’s operating structure 5.00 leaves the firm susceptible to lower than average inflows, with our target price sensitive 4.00 to the percentage change in average annual generation volumes.

High Dividend Pay-Out Set to Continue NZX 50 MEL offers an attractive dividend yield of 6.7%, higher than the average dividend yield Competitor Average of both the NZX50 and its competitors and a payout ratio in excess of 100% of net income MEL (Figure 19). MEL’s high dividend payout is set to continue with the firm’s capital Source: Bloomberg management programme still to distribute $438m over the next four years on top the firm’s ordinary dividend. We see a 4% average annual growth rate of ordinary dividends to be sustainable over the forecast period, supported by strong cash flow growth and an increase in financial leverage.

Figure 20. Debt-to-Equity Financial Flexibility Maintained Ratio Forecasts MEL has historically maintained a debt-to-equity ratio well below that of its peers in 40.00% order to deal with reductions in cash flow arising from years of low inflows and storage levels. With a current debt-to-equity ratio of 25% relative to an industry average debt-to- 35.00% equity ratio of approximately 50%, the firm has plenty of financial flexibility should 30.00% adverse weather conditions arise. We forecasted debt-to-equity as increasing to 25.00% approximately 35% before declining towards our long-term target ratio of 30%. While maintaining a strong liquidity position and holding an interest coverage ratio in excess of 20.00% 6x. 15.00% Improving Performance Metrics FY2016 MEL was one of the weaker performers in the electricity sector in terms of ROA and ROE, with an ROE of 3.6%, significantly below the industry average, although partly Source: Company Data, Team Estimates driven by the firm’s low financial leverage (Table 8). Our model shows improvements in both measures with ROA increasing by 4.86% over our forecast period, driven by Table 8. MEL ROE vs. Industry improvements in both asset turnover and operating profit margin, with an increase in Average leverage providing further growth in ROE. Increases in operating profit margin come as ROE (% ) Meridian Average a result the Generation EM/Generation EBITDA margin increasing to 90% by 2026, more 2014 4.98 5.82 than offsetting the declining Retail EM/Retail EBITDA. Growth in generation margin is 2015 5.24 4.92 primarily due to increasing wholesale spot prices improving generation revenue without 2016 3.57 6.45 requiring expenditure, but also come as a function of the $57m decrease in transmission Source: Worldscope costs between 2019 and 2020. Financial Ratios: No Closure Scenario As at 30/6 2015 2016 2017F 2018F 2019F 2020F 2021F 2022F 2023F 2024F 2025F 2026F Du Pont Analysis Asset Turnover 12.5% 11.8% 13.3% 13.3% 13.8% 14.6% 14.9% 15.6% 16.3% 16.9% 17.6% 18.4% Operating Profit Margin 37.6% 39.8% 45.1% 43.1% 46.8% 50.6% 50.6% 51.4% 51.6% 51.7% 51.9% 52.1% Return on Assets 4.7% 4.7% 6.0% 5.7% 6.5% 7.4% 7.6% 8.0% 8.4% 8.8% 9.2% 9.6% Finance and Tax Effects 68.8% 46.0% 60.7% 59.9% 60.9% 61.4% 60.5% 61.3% 62.3% 63.2% 64.0% 64.7% Financial Leverage 1.63 1.65 1.70 1.73 1.78 1.83 1.88 1.89 1.88 1.88 1.88 1.89 Return on Equity 5.2% 3.6% 6.2% 5.9% 7.0% 8.3% 8.6% 9.3% 9.8% 10.4% 11.0% 11.7% Financial Leverage Debt to Equity 23.8% 25.0% 26.5% 28.4% 31.1% 35.6% 36.4% 34.7% 33.1% 31.6% 30.3% 29.2% Debt to Debt + Equity 19.2% 20.0% 20.9% 22.1% 23.7% 26.3% 26.7% 25.8% 24.9% 24.0% 23.2% 22.6% Interest Coverage 4.54 5.58 6.57 6.03 6.54 7.09 6.56 6.82 7.42 8.12 8.89 9.70 Liquidity Current Ratio 69.9% 79.1% 84.5% 83.0% 63.5% 63.5% 82.3% 85.8% 89.0% 92.1% 95.2% 98.1% Cash Ratio 25.1% 39.5% 38.8% 41.3% 19.1% 20.0% 39.2% 39.0% 41.0% 42.4% 43.9% 45.5% Market Earnings per Share (NI) 0.10 0.07 0.12 0.11 0.12 0.14 0.14 0.15 0.16 0.16 0.17 0.17 Dividend per Share 0.15 0.20 0.19 0.20 0.20 0.21 0.17 0.18 0.19 0.20 0.20 0.21 Payout Ratio 1.56 2.72 1.62 1.79 1.62 1.47 1.21 1.20 1.20 1.21 1.23 1.24

Figure 21. MEL Hydro Investment Risks Generation vs. EBITDAF Operational Risk - Adverse Hydrological Conditions (OR1) GWh $M As 90% of MEL’s generation is produced from hydro dams, earnings are heavily 13000 700 influenced by seasonal conditions such as rainfall and snow melt, with a 95% correlation 12000 650 between past five year hydro generation volumes and EBITDAF (Figure 22). In times of 11000 low storage levels wholesale spot prices are typically high forcing MEL to buy electricity 600 at a high price in order to satisfy contractual commitments. 10000 550  Likelihood and Impact: The impact of adverse hydrological conditions can be 9000 evidenced through the most recent low rainfall year, 2012, which saw EBITDAF 500 21.2% lower than the 2011-2016 average of $578.13M. The likelihood of future 8000 adverse hydro conditions cannot be predicted with any certainty. 7000 450  Mitigating Factor: In April 2016 MEL reached an agreement with Genesis to push 6000 400 back the closure of the Huntly Rankine units, a thermal generator. The deal was reached to counter periods of low renewable generation and volatile wholesale prices, particularly in times of peak demand. This agreement should help dampen Total Hydro EBITDAF volatility in wholesale markets, especially during dry years where MEL faces its Source: Company Data greatest exposure to rising wholesale prices.

Figure 22. EBITDAF under Operational Risk - Tiwai Shutdown (OR2) Different Tiwai Closure Scenarios The closure of Tiwai is the largest single risk to MEL. A recent period of low Aluminium prices and a strong NZD/USD has reduced the smelters profitability, threatening its $1,000 viability and causing the plants owners to consider cutting production or closing the plant. $900  Likelihood and Impact: The closure of Tiwai would cause a short-term $800 oversupply, putting downward pressure on wholesale electricity prices. This would $700 be detrimental to MEL’s short-term earnings, with our analysis suggesting a 10.3% $600 drop in share price were the smelter to close in 2019. We view the implied price $500 increase from aluminium futures, solid first half 2016 performance for its parent $400 company Rio Tinto, and an expected $21M p.a. saving in transmission costs as xxiv $300 encouraging signs for the continuation of the plant . (Appendix J)  Mitigating Factor: Current transmission constraints from the Manapouri to the national grid would require MEL to undergo an 18 month upgrade to the station

2019 Closure 2020 Closure should NZAS terminate the contract. However, the contracted 12 month notice period allows MEL to minimise transmission shortages to six months and the release 2022 Closure No Closure from an onerous contract provides upside to MEL’s earnings over the long horizon. Source: Energy Link, Company Data, Operational Risk - Power Station Production Risk (OR3) Team Estimates – Appendix J Plant failure or significant repair requirements (OR3a), a natural disaster (OR3b) or Figure 23. Risk Matrix changes in generation technology (OR3c) would likely lead to a decrease in generation efficiency for MEL, negatively affect cash flows.  Likelihood and Impact: The likelihood of significant repairs or damages caused by a natural disaster remain low, however, lack of geographical dispersion of MEL’s OR3b OR2

generation plants leaves MEL susceptible to a large natural disaster. The High RR1 OR1 introduction of solar or battery packs may lead to decreases in average household electricity consumption. OR3a  Mitigating Factor: MEL has decreased maintenance capex for its wind farms by

Medium locally sourcing repairs and replacements parts, reducing supply chain risk and cost IMPACT of components and freightxxv. Additionally, MEL currently has insurance coverage of $935M for material damages and business interruptions. We view solar and

Low OR3c RR2 battery packs as posing little threat to MEL’s short to medium-term retail demand due to the cost inefficiency and expected slow diffusion of productxxvi Low Medium High

PROBABILITY Regulatory and Legislative Risk – Electricity Market Regulatory Reform (RR1) Source: Team Estimates MEL currently operates in a competitive market with individual retailers able to set their own prices. The proposed regulatory reform by Labour in 2013 would make the Table 9. Risks and Mitigating electricity market a single-buyer model. Factors  Likelihood and Impact: The proposed regulatory change would adversely affect MEL’s generation and retail businesses by removing the wholesale market and Risk Mitigating Factor preventing MEL from setting its own prices. The political campaigning surrounding Operational Risk this issue took place in 2013 and for this reason we view the likelihood of the MEL and GNE agreement to proposed change as low. Adverse Hydro Conditions keep Huntly Rankine open  Mitigating Factor: The complexities inherent in the proposed changes and time to until 2022 implement the single-buyer model would be lengthy, in our view, allowing MEL to Manapouri Station Upgrade make the necessary strategic adjustments. Tiwai Closure & loss of Onerous NZAS Regulatory and Legislative Risk – Australian Market (RR2) contract MEL’s renewable energy generation and retail businesses in Australia rely on sales to the Station or Turbine repair Locally sourced Repairs wholesale spot market and its Powershop customers. Political uncertainty towards RETs Natural Disaster Insurance Coverage - $935M has created uncertainty around the long-term viability of MEL’s generation plants. Technology Advancement Active market participation  Likelihood of Impact: The current government appear to be committed to meeting Regulatory and Legislative Risk RET’s. The impact on the feasibility of MEL’s Australian generation would be significant should RET’s be revised or abolished as this would decrease the demand Single-Buyer Electricity Time to make strategic for LGC’s, putting downward pressure on prices and lowering MEL’s earnings. Market adjustments  Mitigating Factor: Increases in societal pressure towards limiting carbon Changes to Australian RET Increased Societal Pressure emissions, especially in developed countries, may limit the likelihood of the Source: Team Analysis Australian government removing the RET’s.

Appendix A: Financial Statements

Income Statement: No Closure Scenario As at 30/06 Unit 2015 2016 2017F 2018F 2019F 2020F 2021F 2022F 2023F 2024F 2025F 2026F NZ Generation Hydro Generation GWh 11,911 12,251 12,374 11,755 11,755 11,755 11,755 11,755 11,755 11,755 11,755 11,755 Wind Generation GWh 1,421 1,456 1,434 1,434 1,434 1,782 1,782 1,782 1,782 1,782 1,782 1,782 Total NZ Generation Volume GWh 13,332 13,707 13,808 13,189 13,189 13,537 13,537 13,537 13,537 13,537 13,537 13,537 NZ GWAP $/MWh 68.10 56.90 70.96 77.05 79.91 86.30 91.85 103.11 107.95 111.33 116.13 120.08 NZ Generation Energy Margin $m 908 780 980 1,016 1,054 1,168 1,243 1,396 1,461 1,507 1,572 1,625 NZ Contracted Sales Tiwai Sales Volume GWh 5,013 5,027 4,776 4,871 4,969 5,068 5,169 5,273 5,378 5,486 5,595 5,707 Tiwai Average Sales Price $/MWh 47.45 47.83 47.83 48.78 49.76 50.75 51.77 52.80 53.86 54.94 56.04 57.16 Tiwai Revenue $m 238 240 228 238 247 257 268 278 290 301 314 326 Tiwai LWAP $/MWh 68.49 56.31 70.67 76.72 79.58 85.96 91.44 102.69 107.54 110.93 115.74 119.69 Cost to Supply Sales $m - 343 - 283 - 337 - 374 - 395 - 436 - 473 - 541 - 578 - 609 - 648 - 683 Tiwai Energy Margin $m - 105 - 43 - 109 - 136 - 148 - 178 - 205 - 263 - 289 - 307 - 334 - 357

Residential and SMB Sales Volume GWh 3,691 3,781 3,827 3,873 3,919 3,966 4,014 4,062 4,111 4,160 4,210 4,260 Corporate and Institutional Sales Volume GWh 2,276 2,188 2,215 2,241 2,268 2,295 2,323 2,351 2,379 2,408 2,436 2,466 Total Retail Contracted Sales Volume GWh 5,967 5,970 6,041 6,114 6,187 6,262 6,337 6,413 6,490 6,568 6,646 6,726 Retail Average Sales Price $/MWh 102.90 105.40 106.36 108.29 110.30 112.11 113.88 115.90 118.27 120.68 123.14 125.65 Retail Contracted Sales $m 614 629 643 662 682 702 722 743 768 793 818 845 Retail LWAP $/MWh 82.56 68.85 79.16 85.94 88.97 95.52 101.97 114.12 119.73 123.40 128.58 132.87 Cost to Supply Sales $m - 493 - 411 - 478 - 525 - 550 - 598 - 646 - 732 - 777 - 810 - 855 - 894 Other Market Transactions $m - 1 2 ------Retail Energy Margin $m 120 220 164 137 132 104 75 11 - 9 - 18 - 36 - 49

Financial Contracts Sold Volume GWh 1,011 1,281 1,146 1,163 1,181 1,198 1,216 1,235 1,253 1,272 1,291 1,310 Financial Contracts Sold Average Price $/MWh 73 61 74 81 83 89 95 107 112 116 120 124 Financil Contracts Sold Revenue $m 73.90 78.01 85.03 93.73 98.40 107.00 116.09 131.68 140.60 147.12 155.54 163.13 Acquired Generation Volume GWh 1,054 1,130 1,119 1,175 1,175 1,175 1,175 1,175 1,175 1,175 1,175 1,175 Acquired Generation Average Price $/MWh 85.70 75.81 89.04 96.70 100.01 107.15 114.54 127.99 134.65 138.81 144.58 149.40 Cost of Acquired Generation $m - 90 - 86 - 100 - 114 - 117 - 126 - 135 - 150 - 158 - 163 - 170 - 175 Net VAS Revenue $m 10 8 12 12 12 12 12 12 12 13 13 13 Other Market Transactions $m - 16 - 19 0 0 0 0 0 0 0 0 0 0 Derivative Contract Energy Margin $m - 23 - 19 - 3 - 8 - 7 - 6 - 6 - 6 - 5 - 3 - 1 1

NZ Energy Margin $m 900 939 1,032 1,009 1,031 1,087 1,108 1,138 1,158 1,179 1,201 1,221

Australia AUS Generation Volume GWh 519 519 519 519 519 519 519 519 519 519 519 519 AUS GWAP $/MWh 85 106 108 110 112 115 117 119 122 124 127 129 AUS Generation Energy Margin $m 44 55 56 57 58 60 61 62 63 64 66 67 AUS Contracted Sales $m 20 42 43 44 45 45 46 47 48 49 50 51 AUS Cost to Supply Contracted Sales $m - 10 - 27 - 28 - 28 - 29 - 29 - 30 - 30 - 31 - 32 - 32 - 33 AUS Contract Sales Energy Margin $m 10 15 15 16 16 16 17 17 17 18 18 18

AUS Energy Margin $m 54 70 71 73 74 76 77 79 80 82 84 85

Total Energy Margin $m 954 1,009 1,104 1,082 1,105 1,163 1,185 1,217 1,239 1,261 1,284 1,306

Generation EBIDAF NZ Generation Energy Margin $m 790 908 780 980 1,016 1,054 1,168 1,243 1,396 1,461 1,507 1,572 Other Revenue $m 10 7 6 8 8 8 8 8 8 8 9 9 Energy Transmission Expense $m - 127 - 120 - 124 - 125 - 127 - 95 - 71 - 72 - 73 - 74 - 76 - 77 Employee Expense $m - 28 - 27 - 29 - 28 - 28 - 29 - 29 - 30 - 30 - 31 - 31 - 32 Other Operating Expenses $m - 51 - 52 - 51 - 51 - 52 - 53 - 54 - 55 - 55 - 56 - 58 - 59 Total Generation/Wholesale Expenses $m - 196 - 192 - 198 - 197 - 200 - 168 - 146 - 148 - 150 - 153 - 156 - 160 NZ Generation EBITDAF $m 594 716 582 783 816 885 1,023 1,095 1,245 1,308 1,351 1,413

Retail EBITDAF Retail Energy Margin $m 167 120 220 164 137 132 104 75 11 - 9 - 18 - 36 Other Revenue $m 20 11 7 13 13 13 13 13 14 14 14 15 Employee Expense $m - 32 - 32 - 30 - 31 - 32 - 32 - 33 - 33 - 34 - 34 - 35 - 36 Electricity Metering Expense $m - 24 - 26 - 30 - 28 - 28 - 29 - 29 - 30 - 30 - 31 - 31 - 32 Other Operating Expenses $m - 32 - 32 - 31 - 32 - 32 - 33 - 33 - 34 - 34 - 35 - 36 - 36 Total Retail Expenses $m - 68 - 79 - 84 - 78 - 79 - 80 - 82 - 83 - 85 - 86 - 88 - 90 Retail EBITDAF $m 99 41 136 86 58 51 22 - 8 - 73 - 96 - 106 - 126

Unallocated and Inter-Segment Items Unallocated: Other Revenue $m 12 32 22 22 22 22 22 22 22 22 22 22 Employee Expense $m - 23 - 22 - 22 - 22 - 22 - 22 - 22 - 22 - 22 - 22 - 22 - 22 Other Operating Expenses $m - 31 - 22 - 20 - 24 - 25 - 25 - 25 - 26 - 26 - 27 - 27 - 28 Net Unallocated $m - 42 - 12 - 20 - 25 - 25 - 25 - 26 - 26 - 27 - 27 - 28 - 28 Intersegment: Other Revenue $m - 15 - 29 - 21 - 22 - 24 - 22 - 23 - 23 - 23 - 23 - 23 - 23 Other Expense $m 2 4 ------Net Inter-Segment $m - 13 - 25 - 21 - 22 - 24 - 22 - 23 - 23 - 23 - 23 - 23 - 23 Total Unallocated and Inter-Segment $m - 55 - 37 - 41 - 46 - 49 - 48 - 48 - 49 - 49 - 50 - 50 - 51

Tiwai and Derivative Trading Energy Margin $m - 66 - 128 - 62 - 112 - 144 - 155 - 185 - 211 - 269 - 294 - 310 - 335

NZ EBITDAF $m 572 592 616 711 681 734 811 828 854 869 884 900

International EBITDAF International Energy Margin $m 33 54 70 71 73 74 76 77 79 80 82 84 Other Revenue $m - - 3 ------Energy Transmission Expense $m - 2 - 3 - 4 - 4 - 4 - 4 - 4 - 4 - 4 - 4 - 5 - 5 Employee Expense $m - 8 - 7 - 11 - 11 - 11 - 12 - 12 - 12 - 12 - 12 - 13 - 13 Other Operating Expenses $m - 10 - 18 - 24 - 24 - 25 - 25 - 26 - 26 - 26 - 27 - 27 - 28 Total International Expenses $m - 20 - 28 - 36 - 39 - 40 - 41 - 41 - 42 - 43 - 44 - 45 - 45 International EBITDAF $m 13 26 34 32 33 34 34 35 36 37 37 38

Total EBITDAF $m 618 650 743 714 768 846 863 890 906 922 939 954

Income Statement: No Closure Scenario As at 30/06 Unit 2015 2016 2017F 2018F 2019F 2020F 2021F 2022F 2023F 2024F 2025F 2026F NPAT Depreciation $m - 218 - 217 - 224 - 226 - 228 - 234 - 239 - 241 - 243 - 244 - 246 - 248 Amortisation $m - 21 - 19 - 19 - 20 - 20 - 20 - 21 - 21 - 22 - 22 - 22 - 23 Depreciation and Amortisation $m - 239 - 236 - 244 - 246 - 248 - 254 - 260 - 262 - 264 - 266 - 269 - 271 Impairment of PPE $m - 33 - 6 - 2 - 2 - 3 - 3 - 3 - 3 - 3 - 3 - 3 - 3 Reversal of Previous Impairment of PPE $m - 10 ------Intangible Assets $m - 2 ------Other Assets $m - 3 ------Impairment of Assets $m - 38 4 - 2 - 2 - 3 - 3 - 3 - 3 - 3 - 3 - 3 - 3 Gain/(loss) on Sale of Assets $m 19 - 1 ------Equity Accounted Earnings of Joint Ventures $m ------Net Change in FV of Electricity Hedges $m - 1 - 15 ------EBIT $m 359 402 498 466 517 589 600 625 639 652 667 680 Interest on Borrowing $m - 79 - 72 - 76 - 77 - 79 - 83 - 91 - 92 - 86 - 80 - 75 - 70 Interest on Financial Lease Payable $m - 6 - 6 - 6 - 5 - 6 - 6 - 6 - 6 - 6 - 6 - 5 - 5 Capitalised Interest $m ------Interest on Energy Option Premium $m - 1 - 2 ------Finance Costs $m - 86 - 80 - 81 - 83 - 85 - 89 - 98 - 98 - 92 - 86 - 80 - 75 Interest Income $m 8 2 4 5 5 2 2 6 6 6 6 6 Net Change in FV of Treasury Instruments $m - 32 - 68 ------EBT $m 249 256 420 388 438 502 504 533 553 573 593 611 Income Tax $m - 2 - 71 - 118 - 109 - 123 - 140 - 141 - 149 - 155 - 160 - 166 - 171 NPAT $m 247 185 302 280 315 361 363 384 398 412 427 440

Statement of Changes in Equity (000's): No Closure Scenario As at 30/06 2015 2016 2017F 2018F 2019F 2020F 2021F 2022F 2023F 2024F 2025F 2026F Dividend Transactions Dividends Paid - 385 - 501 - 488 - 500 - 511 - 529 - 439 - 459 - 479 - 501 - 523 - 547 Ordinary - 272 - 368 - 379 - 390 - 402 - 420 - 439 - 459 - 479 - 501 - 523 - 547 Special - 113 - 133 - 110 - 110 - 110 - 110 ------Share-based Transactions - 1 ------Share Capital - 2 ------Share option Reserve 1 ------

Statement of Changes in Equity Opening Equity 4,635 4,749 5,050 4,864 4,644 4,448 4,280 4,204 4,129 4,048 3,959 3,862 Share Capital - 2 ------Share Option Reserve 1 ------Revaluation Reserve 237 641 ------FX Translation Reserve 18 - 23 ------Cash Flow Hedge Reserve - 2 ------Available for Sale Reserve ------Retained Earnings - 138 - 316 - 186 - 220 - 196 - 168 - 76 - 75 - 81 - 89 - 96 - 107 Total Equity 4,749 5,050 4,864 4,644 4,448 4,280 4,204 4,129 4,048 3,959 3,862 3,756

Balance Sheet (000's): No Closure Scenario As at 30/06 2015 2016 2017F 2018F 2019F 2020F 2021F 2022F 2023F 2024F 2025F 2026F Assets Cash And Equivalents 69 118 156 176 63 68 188 193 199 204 208 213 Financial Instruments 48 71 43 47 46 47 49 50 52 53 54 55 Accounts Receivable 191 194 245 240 246 259 263 270 275 280 285 290 Other Assets 19 23 11 11 11 12 12 12 12 13 13 13 Assets Classified as Held for Sale 7 ------Total Current Assets 334 406 455 474 365 385 513 526 539 549 560 571

Gross Property, Plant & Equipment 7,169 7,857 7,921 7,985 8,176 8,366 8,429 8,492 8,556 8,619 8,683 8,746 Accumulated Depreciation - 72 - 86 - 310 - 537 - 765 - 999 - 1,238 - 1,478 - 1,721 - 1,965 - 2,212 - 2,460 Net Property, Plant & Equipment 7,097 7,771 7,610 7,448 7,411 7,367 7,191 7,014 6,835 6,654 6,471 6,287

Goodwill ------Intangible Assets 47 47 48 49 50 51 52 53 54 55 56 57 Financial Instruments 147 274 132 130 133 140 142 146 149 151 154 157 Deferred Tax Assets 36 40 40 40 40 40 40 40 40 40 40 40 Total Non-Current Assets 230 361 220 219 222 230 234 239 243 246 250 254

Total Assets 7,661 8,538 8,286 8,141 7,999 7,983 7,938 7,779 7,616 7,450 7,282 7,112

Liabilities Employee Entitlements 16 15 12 13 13 13 14 14 15 15 15 16 Current Portion of Term Borrowings 213 214 219 224 235 259 260 244 227 212 199 186 Finance Lease Payable 1 1 1 1 1 1 1 1 1 1 1 1 Current Taxes Payable 22 30 33 36 36 36 38 39 40 41 42 42 Payables and Accruals 192 205 233 256 250 256 269 274 282 287 292 297 Financial Instruments 34 48 40 40 40 40 40 40 40 40 40 40 Total Current Liabilities 478 513 539 571 576 606 623 613 605 596 589 583

Long-Term Debt 863 1,000 1,024 1,048 1,099 1,211 1,215 1,140 1,063 993 929 870 Finance Lease Payable 51 47 45 46 48 53 53 50 47 44 41 38 Deffered Taxes 1,400 1,617 1,617 1,617 1,617 1,617 1,617 1,617 1,617 1,617 1,617 1,617 Provisions 8 8 8 8 8 8 8 8 8 8 8 8 Financial Instruments 101 203 143 157 153 157 165 168 173 176 179 182 Term Payables 12 100 46 50 49 50 53 54 55 56 57 58 Total Non-Current Liabilities 2,435 2,975 2,883 2,926 2,975 3,097 3,111 3,037 2,963 2,894 2,831 2,774

Total Liabilities 2,913 3,488 3,422 3,496 3,551 3,703 3,734 3,650 3,569 3,491 3,419 3,356

Equity Share Capital 1,597 1,597 1,597 1,597 1,597 1,597 1,597 1,597 1,597 1,597 1,597 1,597 Share Option Reserve 1 1 1 1 1 1 1 1 1 1 1 1 Revaluation Reserve 3,311 3,952 3,952 3,952 3,952 3,952 3,952 3,952 3,952 3,952 3,952 3,952 FX Translation Reserve - 5 - 28 - 28 - 28 - 28 - 28 - 28 - 28 - 28 - 28 - 28 - 28 Cash Flow Hedge Reserve - 3 - 3 - 3 - 3 - 3 - 3 - 3 - 3 - 3 - 3 - 3 - 3 Available for Sale Reserve 1 1 1 1 1 1 1 1 1 1 1 1 Retained Earnings - 152 - 468 - 654 - 874 - 1,070 - 1,239 - 1,315 - 1,390 - 1,471 - 1,559 - 1,656 - 1,763 Total Common Equity 4,749 5,050 4,864 4,644 4,448 4,280 4,204 4,129 4,048 3,959 3,862 3,756

Supplementary Items Net Assets 4,748 5,050 4,864 4,644 4,448 4,280 4,204 4,129 4,048 3,959 3,862 3,756 Total Debt 1,128 1,262 1,289 1,319 1,383 1,525 1,529 1,435 1,339 1,251 1,169 1,095 Shares Outstanding 2,561 2,561 2,561 2,561 2,561 2,561 2,561 2,561 2,561 2,561 2,561 2,561

Forecast Assumptions

Income Statement Items Assumption Energy Margin Generation Volume Decline back to historical mean levels over FY2017-18 then held constant. See Appendix F GWAP Energy Link price paths weighted by generation location Tiwai Sales Volume FY2017 decline of 5% followed by a constant 2% increase Tiwai Average Sales Price Calculated as:

Tiwai LWAP Wholesale spot price forecast for Lower South Island Financial Contracts Sold Price Calculated from wholesale spot price forecasts Financial Contracts Sold Volume Growth rate of 2% Acquired Generation Volume Inverse of generation growth rate Acquired Generation Average Price 120% of Financial Contracts Sold Price, in line with historical estimates Retail Contracted Sales Volume Growth rate of 1.2% per annum. See Appendix G Retail Average Sales Price Growth rate in line with inflation forecasts Retail LWAP Wholesale spot price forecasts weighted by number of ICP's per region plus a 7% lines loss charge Other Market Transactions Historic average growth rate Australia Energy Margin Generation volume held constant, 2% growth rate applied to GWAP and cost to supply sales EBITDAF Other Revenues Historic average growth rate NZ Energy Transmission Expense Increase in line with inflation before declining $57m per year, spread over two years Electricity Metering Expense Constant proportion of retail sales, in line with historic proportion Employee Expense Growth rate in line with inflation forecasts Other Revenue and Expenses Historic average growth rate AUS Energy Transmission Expense Constant proportion of generation sales, in line with historic proportion NPAT Depreciation 3.3% of Gross PPE, in line with historic rate Amortisation 40% of Intangible Assets, in line with historic rate Impairment of PPE Constant proportion of PPE Other Non-Cash Items Historic average Interest Rate on Borrowing Historic implied interest rate of 6% Interest on Financial Leases Historic implied interest rate of 12% Interest Income Historic implied interest rate of 3% Income Tax Corporate tax rate 28%

Balance Sheet Assumption Assets Cash And Equivalents Historic average proportion of Total Energy Margin less adjustment for capital expenditure Financial Instruments Historic average proportion of Total Energy Margin Accounts Receivable Historic average proportion of Total Energy Margin Other Assets Historic average proportion of Total Energy Margin Assets Classified as Held for Sale Historic average proportion of Total Energy Margin Intangible Assets Growth rate of 2% Financial Instruments Historic average proportion of Total Energy Margin Property Plant and Equipment Increasing with annual $65m stay-in-business CAPEX plus $250 FY2019-20 investment Liabilities Employee Entitlements Historic average proportion of Total Energy Margin Current Taxes Payable Historic average proportion of Total Energy Margin Payables and Accruals Historic average proportion of Total Energy Margin Financial Instruments Historic average proportion of Total Energy Margin Deffered Taxes Held constant over forecast period Provisions Historic average proportion of Total Energy Margin Financial Instruments Historic average proportion of Total Energy Margin Term Payables Historic average proportion of Total Energy Margin Long-Term Debt Flexible Account Financial Lease Payable Flexible Account

Appendix B: Progression Matrix for Mixed Ownership State-Owned Enterprises: Shareholder Rights

IFC-World Bank Progression Matrix for State-Owned Enterprises: Shareholder Rights

LEVEL REQUIREMENT SATISFIED LEVEL 1 Acceptable Corporate governance practices The company's legal framework treats all shareholders of the same l class equally with respect to voting rights, subscription rights, and P transfer rights Shareholders participate in the shareholders' meeting and receive l P dividends l Changing the articles requires supermajority P LEVEL 2 Extra Steps to Ensure Good Corporate Governance Shareholders are provided with accurate and timely information on l the number of shares of all classes held by the state and other P majority shareholders

The SOE encourages minority shareholders to participate in the l shareholder meetings P l Minority shareholders may nominate board members P

LEVEL 3 Majority Contribution to Improving Corporate Governance Nationally

Rights of shareholders are protected during new-share issues and l P changes of control, including privatisations and re-nationalisations

Shareholders are provided details on special rights the state has in l the SOE (golden shares) and control through government-linked P entities

Rules on related-party transactions address transactions with the l government and other SOEs and require recusal by interested P shareholders.

Effective board representation of minority shareholders is provided l P by cumulative voting or similar mechanism Minority shareholders can ask questions at the shareholders l P meeting and influence its agenda

All securities' holders are treated equally with respect to information l P disclosure (fair disclosure). LEVEL 4 Leadership

The state has no special rights in the company (golden shares) l P beyond its ownership. Supermajority approval is required for large, extraordinary l P transactions.

The SOE's history of equitable treatment of shareholders evidences l P consistent conformity with international market expectations

Source: World Bank Group – Corporate Governance of State-Owned Enterprises

Our analysis of MEL following the IFC-World Bank progression matrix indicated that MEL meets all requirements at each of the specified levels to ensure shareholder rights are maintained. We believe that this adequately satisfies investor concerns regarding their rights as shareholders.

Appendix C: ISS Methodology Rating

We implemented the Institutional Shareholder Service (ISS) rating methodology to assess MEL’s corporate governance and the threat of management to shareholders.

Key 1 Insignificant threat to Shareholders 2 Low threat to Shareholders 3 Moderate threat to Shareholders 4 Significant threat to Shareholders 5 High threat to Shareholders

Disclosure and Transparency – INSIGNIFCANT (1) Financial disclosures adhere to NZX and ASX best practice code. Any non-GAAP figures reported, such as EBITDAF, are disclosed as such. Full access to MEL’s annual and interim reports are readily and easily accessible through their online investor centre. MEL has a well-functioning Audit and Risk Committee as well as an internal and external audit function. MEL is committed to ensuring full disclosure as evidenced by their recommendation to the Auditor-General that there be a lead suit partner rotation after a maximum of five years.

Executive Management – LOW (2) MEL has a well-performing executive team with a range of industry and financial experience. The executive team has an average tenure of four years, with a maximum of eight years and the most recent appointment coming in July, 2016. The executive members are from both internal and external appointments which we view as conducive to ensuring retained experience and gaining external knowledge. The executive team meets MEL’s gender diversity targets.

Board of Directors – LOW (2) The board of directors provide a range of business and industry specific experience. Each member of the board is an independent director with tenure ranging between four and eight years and the current composition adheres to MEL’s gender diversity targets. The board has well-established appointment and dismissal guidelines as outlined in the board charter. The compensation of directors is competitive to ensure the appointment of capable individuals while remaining within a reasonable bound of the industry. Recent researchxxvii has raised the concern surrounding the ability of ‘busy’ directors to properly govern a firm, however, MEL’s directors have an average of 4.5 directorship, which is within the recommended guidelines, giving us confidence in their ability to govern MEL.

Rights and Obligations of Shareholders – LOW (2) Upholding the rights of minority shareholders is vital to MEL as a mixed-ownership, majority SOE. We view MEL as meeting all necessary requirements in ensuring shareholder rights as outlined in IFC-World banks progression matrix for SOE’s. MEL currently offers ordinary shares with 1:1 voting rights.

Takeover Defence – INSIGNIFICANT (1) There is no threat of takeover as MEL is a mixed-ownership state-owned enterprise with the Crown currently owning 51.02% and a maximum 10% restriction minority ownership.

SCORE: 2/5 Our analysis arrives at a low Institutional Shareholder Service rating. (Note: Our ISS rating was rounded to a whole number figure)

Criteria Risk Board Structure Low Shareholder Rights Low

Compensation Low Audit & Risk Oversight Low ISS Rating Low

Source: Company Data, Team Estimates

Appendix D: Electricity Demand Drivers

Total Electricity Demand

Regression Statistics Variable Coefficient T-stat R-Square 0.9539 Intercept -0.01338 -3.3983 Adjusted R-Square 0.9473 Log (GDPt/GDPt-1) 0.322085 1.3855 Log(AverageTempt/AverageTempt-1) Number of Obs 41 -0.14216 -24.1765 Log(GasPricet/GasPricet-1) -0.11433 -1.6349 F statistic 144.7665 Summer Dummy Variable 0.02227 3.6202 Source: EMI, NIWA, Westpac, Team Estimates Winter Dummy Variable 0.02881 4.6275

Source: EMI, NIWA, Westpac, Team Estimates

To illustrate the drivers of total electricity demand and the breakdown of GDP as a driver of demand we used regression analysis on quarterly data from Q4 2005-Q4 2015. To ensure a non-spurious regression result we used log first differenced variables for: Total Electricity Demand; GDP; Average Temperature; and Gas Prices. Our dependent variable for the regression was total electricity demand growth.

The result of the regression shows a positive but insignificant relationship between total electricity demand and GDP showing the breakdown of the macroeconomic factor as a driver of demand during the sample period. Average temperature is inversely related with electricity demand growth and the winter dummy variable is positively related with electricity demand, with both being highly significant as expected. Natural gas prices and the summer dummy variable are of the wrong coefficient and while natural gas prices is insignificant our summer dummy variable is significantly positively related to electricity demand. The positive relationship may be attributable to a large agricultural demand over summer due to irrigation. Further, our data sample includes 2008 and 2012 which had low rainfall levels and probable high levels of irrigation.

Our regression analysis had a high adjusted R-square value of 94.73% and highly significant F-statistic of 144.77, suggesting our model performed well in explaining the variation in total electricity demand over the sample period. Our residual analysis confirmed our residuals were ‘white noise’ increasing the validity of our regression analysis.

Retail Electricity Demand

Regression Statistics Variable Coefficient T-stat R-Square 0.9778 Intercept -0.0515 -1.500 Adjusted R-Square 0.9708 Log (Populationt/Populationt-1) 43.31948 1.6911 Number of Obs 22 Log(AverageTempt/AverageTempt-1) -0.4628 -9.8583 F statistic 140.8454 Log(GasPricet/GasPricet-1) 0.058228 0.099314 Summer Dummy Variable -0.01589 -0.4968 Source: EMI, NIWA, Westpac Economics, Team Estimates Winter Dummy Variable 0.1972 2.1642 Source: EMI, NIWA, Westpac Economics, Team Estimates

Following the same methodology as above, we used regression analysis to examine the relationship between demand drivers and quarterly retail electricity demand from Q3 2010- Q4 2015. Our dependent variable for the regression was retail electricity demand growth and our independent variables were as above but with log first difference of population instead of log first difference of GDP.

The result of the regression shows a positive but insignificant relationship between retail demand growth and population growth as expected. The remaining variables have the expected coefficients and significance.

Our regression performed well with an adjusted R-square value of 97.78% and a highly significant F-statistic of 140.85. Residual analysis confirmed our residuals were ‘white noise’ increasing the validity of our regression analysis.

Appendix E: Porters Five Forces Analysis Threat of New Entrants 5 4 3 KEY Competitive 2 Threat Of Rivalry Substitutes 0 0 No threat to MEL 1 1 1 Insignificant threat to MEL 0 2 2 Low threat to MEL 3 3 Moderate threat to MEL 4 4 Significant threat to MEL 5 5 High threat to MEL Supplier Power Buyer Power

Generation Retail

Source: Team Estimates Generation

Threat of New Entrants – LOW (1) Large capital outlay requirements create a barrier to entry limiting the likelihood of new entrants to the generation sector. The five major competitors have dominated the market and hold the majority of available hydro and geothermal generation locations within New Zealand’s limited geography. The barriers to entry for new entrants to the generation sector give MEL and the sector as a whole very little threat of displacement from potential new entrants.

Threat of Substitutes – LOW (2) New Zealand generation can be broken into five energy sources; hydro, geothermal, thermal, wind and cogeneration. Currently, hydro is makes up the largest percentage of total generation. A 90% 2025 Renewable energy target from the New Zealand Government means MEL as a wholly renewable energy generator has little threat from its competitors with a less favourable mix. Currently, large scale solar or battery packs appear to have little viability due to cost inefficiency and are of little threat to MEL’s current generation business.

Buyer Power – MODERATE (3) The generation sector is a competitive market where generators (suppliers) sell to the wholesale spot market and create an equilibrium nodal price based on supply and demand. The wholesale market limits the ability of retailers (buyers) to affect prices. Prices are generally affected by the level of total generation and level of demand.

The NZAS contract currently accounts for 41% of MEL’s total generation and approximately 13-15% total national demand. Due to this, NZAS holds significant bargaining power to ensure prices remain low. Further, NZAS has the option to terminate the current contract as of 1st of January 2017 increasing the bargaining power of the smelter over MEL.

Supplier Power – NO THREAT (0) Not applicable as there is no supplier of generation to MEL.

Intensity of Competitive Rivalry – LOW (2) The generation industry is dominated by New Zealand’s five gentailers: Contact Energy, Genesis Energy, Mercury Energy, Meridian Energy, and . Steady market share trends suggest competition between generators for market share is minimal. Furthermore, intensity of competition is restricted in the sector by the length of time required to add additional generation capacity through new builds.

Retail Threat of New Entrants – MODERATE (3) Volatile wholesale spot prices provide MEL as a vertically integrated gentailer with a distinct advantage over potential new entrants to the sector, particularly pure retailers. Pure retailers ability to penetrate the market has been limited with Pulse Energy boasting the largest number of ICP’s at approximately 55,000 outside of the big five gentailersxxviii .

Threat of Substitute – SIGNIFICANT (4) Lack of product differentiation of retail electricity leaves the threat of substitution high for MEL. The cost of acquiring and maintaining customers has increased and a focus on customer experience has become a point of emphasis within the sector. Almost all retail companies offer significant savings or cash offers for switching making for a negative cost of change. MEL’s Powershop subsidiary continues to receive awards for customer satisfaction and MEL is competitively priced, however, threat of substitution remains a significant risk factor to MEL’s retail arm.

Power of Suppliers – INSIGNIFICANT The retail market works on the same wholesale spot market as described for generators meaning that the power of generators to affect prices is driven by supply and demand and mitigates their ability to influence MEL.

Power of Buyers - MODERATE (3) The market as currently constructed gives retail consumers’ high leverage over the energy companies through threat of switching provider. Increased switching rates and an increase in the cost of acquiring and maintaining customers provides evidence of the power of buyers. Ultimately buyers are price-takers, however, their ability to switch providers at no-cost or even negative cost gives them the ability to ensure market prices remain competitive between retailers.

Intensity of Competitive Rivalry – SIGNIFICANT (4) The retail sector continues to be dominated by the five largest companies, however, competition is high with a total of 22 providers competing amongst a small market. The level of competition has led to continued growth in the number of switches, however, it has done little to disrupt the dominance of the big five gentailers. The market appears to be reaching full saturation with no increase in the number of retailers in 2016 compared with increases of four in both 2014 and 2015. Despite this, with a small market and a large number of rivals the intensity of the competitive rivalry remains significant.

Appendix F: Hydro and Wind Generation ADF Tests

MEL Monthly Wind Generation (GWh) MEL Hydro Generation (GWh)

230 (GW 2000 (GW

210 1800

190 1600 170 1400 150 1200 130 1000 110 800 90

600

05/2016 07/2016 2007 09/2014 11/2014 01/2015 03/2015 05/2015 07/2015 09/2015 11/2015 01/2016 03/2016 09/2016 1997 1998 1999 2000 2001 2002 2003 2004 2005 2008 2009 2010 2011 2012 2013 2014 2015

Mackinnon Critical Values Significance level 1% 5%

Critical Value -3.43 -2.86

ADF Test of Stationarity ADF Test of Stationarity

Variable Coefficient T-statistic Variable Coefficient T-statistic Wind Generation -0.8886 -4.0594 Hydro Generation -0.3371 -6.8382 Constant 298.3905 4.0443 Constant 441.4295 6.802

ADF stationarity tests confirm the mean reverting nature of both MEL’s wind and hydro generation volumes. A co-efficient more negative than the critical value indicates rejecting the null hypothesis of non-stationarity. Therefore, both hydro and wind generation are stationarity at the 1% level justifying our use of a historical average during the forecast period.

Appendix G: Vector Autoregressive Model Forecast of Electricity Demand

0.6

0.4

0.2

0

-0.2

-0.4 Forecast Lower CI Upper CI

-0.6

2018 2021 2024 2026 2016 2016 2016 2016 2017 2017 2017 2017 2018 2018 2018 2019 2019 2019 2019 2020 2020 2020 2020 2021 2021 2021 2022 2022 2022 2022 2023 2023 2023 2023 2024 2024 2024 2025 2025 2025 2025 2026 2026 2026

We used a vector autoregressive model (VAR) to forecast quarterly total electricity industry demand growth in New Zealand for the period 2016-2026. Total electricity demand was used over retail demand due to availability of data. We assumed that retail electricity demand would remain a constant proportion of total electricity demand as it has in the past 5 years. Our model was:

푡−6 푡−6 푖 퐷퐸푀퐴푁퐷푡= α + trend + ∑푛=1 푃 𝑝 + ∑푛=1 퐴 𝑔 𝑝 + ∑푖=1 푄 푦 퐷 + εt Initial testing verified the stationarity of each of the variables and Johansen trace tests confirmed no cointegrating relationships existed between variables, suggesting the suitability of the VAR model. We specified subset restrictions to ensure that average temperature and population forecasts were effected only by their own lags and not by electricity demand. The model was used as guidance for forecast inputs and represents a simplified model for forecasting electricity demand growth. Despite this our forecast appeared to generate a reasonable approximation with a slow upward trend for electricity demand growth, in line Energy Link expectations.

To identify a forecast rate we took the Median annual electricity demand growth forecast. The median year was chosen to minimise the potential effect of model errors and large confidence intervals in the latter period of the forecast. Our forecast rate using the method outlined was 1.2%.

Residual analysis confirmed our residuals are ‘white noise’.

Average Temperature Forecast Population growth Forecast

20 0.014 17.5 0.012 15 0.01

12.5 0.008 0.006 10 0.004 7.5 0.002

5 0

2020Q3 2023Q1 2025Q3 2016Q1 2016Q3 2017Q1 2017Q3 2018Q1 2018Q3 2019Q1 2019Q3 2020Q1 2021Q1 2021Q3 2022Q1 2022Q3 2023Q3 2024Q1 2024Q3 2025Q1 2026Q1 2026Q3

2020Q3 2016Q1 2016Q4 2017Q3 2018Q2 2019Q1 2019Q4 2021Q2 2022Q1 2022Q4 2023Q3 2024Q2 2025Q1 2025Q4 2026Q3

forecast lower CI upper CI forecast lower CI upper CI

To forecast average temperature and population growth we used autoregressive six models. These models, once again, represent a simplified approach to obtain a reasonable estimate of future temperature and population growth. The forecasts generated feed in to the vector autoregressive model above to populate the required lags in the future periods.

Appendix H: Valuation

FCFF (000's): No Closure Scenario 2017F 2018F 2019F 2020F 2021F 2022F 2023F 2024F 2025F 2026F TV Net Income 302 280 315 361 363 384 398 412 427 440 450

Non Cash Charges Depreciation 244 246 248 254 260 262 264 266 269 271 271 Impairment 2 2 3 3 3 3 3 3 3 3 3 Deffered Tax Adjustement 40 40 40 40 40 40 40 40 40 40 - Total Non-Cash Charges 286 288 291 297 303 305 307 310 312 314 274

Interest Expense 81 83 85 89 98 98 92 86 80 75 - After Tax Interest Expsense 59 60 61 64 70 71 66 62 58 54 54

Capital Expenditure - 66 - 66 - 194 - 193 - 66 - 66 - 66 - 66 - 66 - 66 - 166 Change in Working Capital - 10 - 27 11 8 - 8 2 - 2 0 0 - 0 - 0

Free Cash Flow to Firm 571 534 484 538 662 695 703 718 731 742 612

Terminal Value 10,036

Present Value of Cash Flows 538 473 404 422 489 484 460 442 424 405 5,480 Valuation Present Value of Firm $ 10,021.61 Less Debt - 1,262 Present Value of Equity $ 8,759.61 Shares Oustanding 2,563 Value per Share $ 3.42 Free Cash Flow to Firm Valuation We utilised a FCFF analysis as our primary valuation method. To do this we applied the assumption outlined in the Valuation section to MEL’s key value drivers in order to forecast annual net profit after tax over a 10 year forecast horizon. NPAT was then adjusted for non-cash charges, interest expense, capital expenditure and changes in working capital to produce yearly free cash flow to firm values. A terminal value was calculated as at the end of our forecast period using a long-run net income growth rate of 2.3% and a terminal value WACC of 8.4%. We applied at terminal value capital expenditure multiplier of 2.5x to account for the significant future capital expenditure required by a generator. These cash flows were then discounted using our forecast period WACC of 6.24% to obtain the present value of the firm. To calculate an intrinsic value per share we deducted debt from the present value of the firm and divided this by the number of shares outstanding. Under our no Tiwai closure scenario this method produced a value per share of $3.42.

DDM (000's): No Closure Scenario 2017F 2018F 2019F 2020F 2021F 2022F 2023F 2024F 2025F 2026F TV Dividends 488 500 511 529 439 459 479 501 523 547 559

Terminal Value 9,175

Present Value of Dividends 460 443 427 416 324 319 314 309 304 299 5,010

Valuation Present Value of Equity $ 8,623 Shares Oustanding 2,563 Value per Share $ 3.37

Dividend Discount Valuation Our second method of valuation utilises a dividend discount model. This incorporates the firms ordinary dividend as well as distributions from the firm’s capital management programme which concludes in 2020. The capital management plan dividends were calculated by taking the firms total stated payout of $625m then deducting the $187m paid up to FY2016. This remaining $438m was then spread over the following four years. Ordinary divided were forecast using a three stage growth rate. A growth rate of 3% was applied to ordinary dividends until FY2020, when the firm’s capital management plan is competed. A growth rate of 4.5% was then applied to the remaining years of the forecast period, with a growth rate of 2.3% applied to the FY2026 dividend to calculate a terminal value. These dividend growth rates were decided upon by picking the highest rate that allowed MEL’s debt to equity ratio to fall below our long-term target ratio of 30% by FY2026. We then calculated the present value of the forecast dividends using our forecast period WACC then summed these and divided by the number of shares outstanding to calculate an intrinsic value per share of $3.37.

EV/EBITDA (000's): No Closure Scenario Company Price EV Forward EBIT Forward EBITDA EV/Fwd EBIT EV/Fwd EBITDA Meridian $ 2.85 $ 8,373 $ 498 $ 743 16.82 11.27 Trustpower $ 7.72 $ 3,811 $ 235 $ 352 16.23 10.82 Contact $ 4.96 $ 5,240 $ 347 $ 541 15.11 9.68 Genesis $ 2.26 $ 3,136 $ 185 $ 332 16.94 9.44 Mercury $ 3.00 $ 5,303 $ 316 $ 492 16.77 10.78

Average 16.26 10.18 Median 16.50 10.23

EV/Fwd EBITDA Industry Median Ratio 10.23 Meridian Fwd EBITDA $ 743.17 Implied EV $ 7,602 Less Net Debt -$ 1,073 Implied Value of Equity $ 6,529 Shares Oustanding 2,563 Value per Share $ 2.55

EV/Fwd EBITDA Relative Valuation The final valuation method we employed was an EV/Fwd EBITDA relative valuation. We first found an industry median EV/Fwd EBITDA multiple using competitor EV/Fwd EBITDA values from Worldscope which was then multiplied by MEL’s forecast forward EBITDA to calculate an implied enterprise value. We then deduct net debt to calculate a value of equity which was then divided by the number shares outstanding to produce an intrinsic value per share off $2.55.

Price Probability Weighted Price

No Closure $ 3.19 90% $ 2.87 2019 Closure $ 2.89 5% $ 0.14 2020 Closure $ 2.94 3% $ 0.09 2022 Closure $ 3.01 2% $ 0.06 Target Price $ 3.16

Target Price To obtain our value per share under our no Tiwai closure scenario the prices calculated above were weighted then summed. This gave us a weighted price of $3.19. We then incorporated a 10% probability of a Tiwai shutdown which gave us our target price per share of $3.16. Appendix I: Beta and WACC Calculations

Company Levered Beta Debt-to-Equity Unlevered Forecast Terminal Trustpower 0.7139 0.7251 0.4690 WACC Period Value Genesis 0.4386 0.4581 0.3298 Risk Free 2.28% 4.78% Corporate Bond Spread 2.75% 2.75% Mercury 1.0809 0.3551 0.8608 Cost of Debt 5.03% 7.53% Contact 1.0288 0.6008 0.7181 Tax Rate 28.00% 28.00% Median Unlevered Beta 0.5936 After Tax Cost of Debt 3.62% 5.42% Risk Free 2.28% 4.78% MRP 6.00% 6.00% Company Unlevered Beta Debt-to-Equity Levered Beta Beta 0.77 0.77 Cost of Equity 6.89% 9.39% Meridian 0.5936 0.2500 0.7684 D/D+E 20% 25% E/D+E 80% 75% WACC 6.24% 8.40% To calculate a beta for MEL we used the pure-play method. We initially calculated the median industry unlevered beta and re- levered this using MEL’s current debt-to-equity ratio. We calculated a WACC using two time periods, a forecast period and a terminal value period. More specifically, we used two separate risk-free rates which were estimated as the past three month average 10 year government bond yield and a 10 year average of the historical 10 year government bond yield respectively. We view the current 10 year government bond yield as accurately representing current market conditions and as being appropriate for our forecast period. However, we believe that using the current risk-free rate in perpetuity would misrepresent long-term expectations. We used a market risk premium of 6% and using the standard CAPM approach we calculated the cost of equity as 6.89% and 9.39% for our forecast period and terminal value period, respectively.

Our after-tax cost of debt for each of our forecast periods was calculated as the relevant risk-free rate plus a corporate bond spread of 275 basis points multiplied by one minus the corporate tax rate of 28%. Using the specified formula we calculated the cost of debt for our forecast and terminal value periods as 3.62% and 5.42%.

As above, when calculating WACC we used two forecast periods. Using a debt-to-assets of 20% and 25% and an equity-to-assets of 80% and 75% for the forecast period and terminal value period we estimated the relevant WACCs as 6.24% and 8.40%. We used a different terminal value debt-to-assets ratio more suitable for long-run sustainability.

Appendix J: Tiwai Closure Scenario Analysis

The closure of the Tiwai smelter is one of the key risks to not only MEL but to the entire New Zealand generation industry due to the effect the closure would have on short-term wholesale prices arising from temporary excess capacity. We modelled separate scenarios for a FY2019, FY2020 and FY2022 shutdown using Tiwai closure scenario price paths provided by Energy Link. In assessing the impact of this on our target price we made the following assumptions:

 Tiwai provides the mandatory 12 month notice prior to closure.  This 12 month notice allows the required transmission line upgrades to begin, with an expected completion time of 18 months, leaving MEL 6 months where total generation output is reduced.  The closure year generation from the Manapouri is limited to 85% of average output before returning to the long-run average based on guidance from MEL that the majority of output would be maintained.  The cost to MEL for the transmission line upgrades is $100 million.  The $40 million transmission expense Tiwai is expected to pay after the TPM is updated in 2019 will be redistributed evenly between the big five generators, allocating MEL an additional $8 million in transmission charges.  The 2019-20 $250 million capital expenditure incorporated into our model is not required if for the 2019 closure scenario.  Dividends are reduced at an appropriate rate to ensure MEL’s debt to equity declines to our long-run target of 30% by 2026.

While we recognise the subsequent significant decline in wholesale prices may bring with it a decline in average retail prices we have not incorporated this into our model. The Energy Link price paths we incorporate into our analysis show wholesale prices increasing markedly following the initial shock to the market, therefore we believe any reduction in retail prices would be short lived.

Figure 15 compares our no closure scenario price with prices from FY2019, FY2020 and FY2022 closure scenarios, showing the negative effect on value declines the further out the closure takes place. Figure 22 shows EBITDAF levels under the three Tiwai closure scenario relative to our no closure scenario. This suggests that while there is a large initial negative impact, EBITDAF converges back to levels seen in our base case, suggesting that while a Tiwai closure would reduce firm value over our forecast period, the closure of the smelter may benefit MEL’s long-term earnings.

Figure 22. EBITDAF under Different Tiwai Figure 15. Tiwai Closure Scenarios

Closure Scenarios 3.25 1000 3.2 900 3.15 800 3.1 700 3.05 600 3 500 2.95 400 2.9 300 2.85 2.8 2.75 2019 Closure 2020 Closure 2.7 Tiwai 2019 Tiwai 2020 Tiwai 2022 No Closure 2022 Closure No Closure

Source: Energy Link, Company Source: Energy Link, Company Data, Team Data, Team Estimates Estimates

Appendix K: Tiwai Closure Scenario Financial Statements

Income Statement (000's): Tiwai Closure 2019 As at June 30th Unit 2016 2017F 2018F 2019F 2020F 2021F 2022F 2023F 2024F 2025F 2026F NZ Generation Hydro Generation GWh 12,251 12,374 11,755 10,914 11,755 11,755 11,755 11,755 11,755 11,755 11,755 Wind Generation GWh 1,456 1,434 1,434 1,434 1,782 1,782 1,782 1,782 1,782 1,782 1,782 Total NZ Generation GWh 13,707 13,808 13,189 12,348 13,537 13,537 13,537 13,537 13,537 13,537 13,537 NZ GWAP $/MWh 56.90 70.71 62.26 33.28 36.30 41.55 46.14 51.17 58.37 65.97 74.81 NZ Generation Energy Margin $m 780 976 821 411 491 562 625 693 790 893 1,013 NZ Contracted Sales Tiwai Sales Volume GWh 5,027 4,776 4,871 ------Tiwai Average Sales Price $/MWh 47.83 47.83 48.78 ------Tiwai Revenue $m 240 228 238 ------Tiwai LWAP $/MWh 56.31 70.39 61.86 ------Cost to Supply Sales $m - 283 - 336 - 301 ------Tiwai Energy Margin $m - 43 - 108 - 64 ------Residential and SMB Sales Volume GWh 3,781 3,827 3,873 3,919 3,966 4,014 4,062 4,111 4,160 4,210 4,260 Corporate and Institutional Sales Volume GWh 2,188 2,215 2,241 2,268 2,295 2,323 2,351 2,379 2,408 2,436 2,466 Total Retail Contracted Sales Volume GWh 5,970 6,041 6,114 6,187 6,262 6,337 6,413 6,490 6,568 6,646 6,726 Retail Average Sales Price $/MWh 105.40 106.36 108.29 110.30 112.11 113.88 115.90 118.27 120.68 123.14 125.65 Retail Contracted Sales $m 629 643 662 682 702 722 743 768 793 818 845 Retail LWAP $/MWh 68.85 78.85 70.27 42.38 46.02 52.82 58.99 65.49 74.57 84.30 95.25 Cost to Supply Sales $m - 411 - 476 - 430 - 262 - 288 - 335 - 378 - 425 - 490 - 560 - 641 Other Market Transactions $m 2 ------Retail Energy Margin $m 220 166 232 420 414 387 365 343 303 258 205 Financial Contracts Sold Volume GWh 1,281 1,146 1,163 1,181 1,198 1,216 1,235 1,253 1,272 1,291 1,310 Financial Contracts Sold Average Price $/MWh 61 74 66 41 45 51 57 64 72 82 92 Financil Contracts Sold Revenue $m 78.01 84.87 77.08 48.43 53.38 62.20 70.57 79.57 91.99 105.61 121.11 Acquired Generation Volume GWh 1,130 1,119 1,175 1,175 1,175 1,175 1,175 1,175 1,175 1,175 1,175 Acquired Generation Average Price $/MWh 75.81 88.87 79.52 49.22 53.46 61.37 68.59 76.20 86.79 98.16 110.91 Cost of Acquired Generation $m - 86 - 99 - 93 - 58 - 63 - 72 - 81 - 90 - 102 - 115 - 130 Net VAS Revenue $m 8 12 12 12 12 12 12 12 13 13 13 Other Market Transactions $m - 19 0 0 0 0 0 0 0 0 0 0 Derivative Contract Energy Margin $m - 19 - 3 - 4 3 3 3 3 3 3 3 4

NZ Energy Margin $m 939 1,032 986 834 908 952 992 1,038 1,096 1,155 1,221

Australia AUS Generation Volume GWh 519 519 519 519 519 519 519 519 519 519 519 AUS GWAP $/MWh 106 108 110 112 115 117 119 122 124 127 129 AUS Generation Energy Margin $m 55 56 57 58 60 61 62 63 64 66 67 AUS Contracted Sales $m 42 43 44 45 45 46 47 48 49 50 51 AUS Cost to Supply Contracted Sales $m - 27 - 28 - 28 - 29 - 29 - 30 - 30 - 31 - 32 - 32 - 33 AUS Contract Sales Energy Margin $m 15 15 16 16 16 17 17 17 18 18 18 AUS Energy Margin $m 70 71 73 74 76 77 79 80 82 84 85 Total Energy Margin $m 1,009 1,104 1,059 908 984 1,029 1,071 1,118 1,178 1,238 1,306 Generation EBIDAF NZ Generation Energy Margin $m 908 780 976 821 411 491 562 625 693 790 893 Other Revenue $m 7 6 8 8 8 8 8 8 8 9 9 Energy Transmission Expense $m - 120 - 124 - 125 - 127 - 195 - 79 - 80 - 81 - 82 - 84 - 85 Employee Expense $m - 27 - 29 - 28 - 28 - 29 - 29 - 30 - 30 - 31 - 31 - 32 Other Operating Expenses $m - 52 - 51 - 51 - 52 - 53 - 54 - 55 - 55 - 56 - 58 - 59 Total Generation/Wholesale Expenses $m - 192 - 198 - 197 - 200 - 268 - 154 - 156 - 158 - 161 - 164 - 168 NZ Generation EBITDAF $m 716 582 780 621 143 338 407 466 531 626 726 Retail EBITDAF Retail Energy Margin $m 120 220 166 232 420 414 387 365 343 303 258 Other Revenue $m 11 7 13 13 13 13 13 14 14 14 15 Employee Expense $m - 32 - 30 - 31 - 32 - 32 - 33 - 33 - 34 - 34 - 35 - 36 Electricity Metering Expense $m - 26 - 30 - 28 - 28 - 29 - 29 - 30 - 30 - 31 - 31 - 32 Other Operating Expenses $m - 32 - 31 - 32 - 32 - 33 - 33 - 34 - 34 - 35 - 36 - 36 Total Retail Expenses $m - 79 - 84 - 78 - 79 - 80 - 82 - 83 - 85 - 86 - 88 - 90 Retail EBITDAF $m 41 136 88 153 340 332 304 280 256 215 168 Unallocated and Inter-Segment Items Unallocated: Other Revenue $m 32 22 22 22 22 22 22 22 22 22 22 Employee Expense $m - 22 - 22 - 22 - 22 - 22 - 22 - 22 - 22 - 22 - 22 - 22 Other Operating Expenses $m - 22 - 20 - 24 - 25 - 25 - 25 - 26 - 26 - 27 - 27 - 28 Net Unallocated $m - 12 - 20 - 25 - 25 - 25 - 26 - 26 - 27 - 27 - 28 - 28 Intersegment: Other Revenue $m - 29 - 21 - 22 - 24 - 22 - 23 - 23 - 23 - 23 - 23 - 23 Other Expense $m 4 ------Net Inter-Segment $m - 25 - 21 - 22 - 24 - 22 - 23 - 23 - 23 - 23 - 23 - 23 Total Unallocated and Inter-Segment $m - 37 - 41 - 46 - 49 - 48 - 48 - 49 - 49 - 50 - 50 - 51

Tiwai and Derivative Trading Energy Margin $m - 128 - 62 - 110 - 68 3 3 3 3 3 3 3 NZ EBITDAF $m 592 616 711 658 438 624 664 700 741 793 846

International Energy Margin $m 54 70 71 73 74 76 77 79 80 82 84 Other Revenue $m - 3 ------Energy Transmission Expense $m - 3 - 4 - 4 - 4 - 4 - 4 - 4 - 4 - 4 - 5 - 5 Employee Expense $m - 7 - 11 - 11 - 11 - 12 - 12 - 12 - 12 - 12 - 13 - 13 Other Operating Expenses $m - 18 - 24 - 24 - 25 - 25 - 26 - 26 - 26 - 27 - 27 - 28 Total International Expenses $m - 28 - 36 - 39 - 40 - 41 - 41 - 42 - 43 - 44 - 45 - 45 International EBITDAF $m 26 34 32 33 34 34 35 36 37 37 38 Total EBITDAF $m 650 743 691 471 659 699 736 778 831 885 946

Income Statement (000's): Tiwai Closure 2020 As at June 30th Unit 2016 2017F 2018F 2019F 2020F 2021F 2022F 2023F 2024F 2025F 2026F NZ Generation Hydro Generation GWh 12,251 12,374 11,755 11,755 10,914 10,914 10,914 10,914 10,914 10,914 10,914 Wind Generation GWh 1,456 1,434 1,434 1,434 1,782 1,782 1,782 1,782 1,782 1,782 1,782 Total NZ Generation GWh 13,707 13,808 13,189 13,189 12,696 12,696 12,696 12,696 12,696 12,696 12,696 NZ GWAP $/MWh 56.90 78.84 85.21 72.46 40.51 38.83 42.69 47.94 56.26 65.29 75.16 NZ Generation Energy Margin $m 780 1,089 1,124 956 514 493 542 609 714 829 954 NZ Contracted Sales Tiwai Sales Volume GWh 5,027 4,776 4,871 4,969 ------Tiwai Average Sales Price $/MWh 47.83 47.83 48.78 49.76 ------Tiwai Revenue $m 240 228 238 247 ------Tiwai LWAP $/MWh 56.31 78.69 85.05 72.22 ------Cost to Supply Sales $m - 283 - 376 - 414 - 359 ------Tiwai Energy Margin $m - 43 - 147 - 177 - 112 ------Residential and SMB Sales Volume GWh 3,781 3,827 3,873 3,919 3,966 4,014 4,062 4,111 4,160 4,210 4,260 Corporate and Institutional Sales Volume GWh 2,188 2,215 2,241 2,268 2,295 2,323 2,351 2,379 2,408 2,436 2,466 Total Retail Contracted Sales Volume GWh 5,970 6,041 6,114 6,187 6,262 6,337 6,413 6,490 6,568 6,646 6,726 Retail Average Sales Price $/MWh 105.40 106.36 108.29 110.30 112.11 113.88 115.90 118.27 120.68 123.14 125.65 Retail Contracted Sales $m 629 643 662 682 702 722 743 768 793 818 845 Retail LWAP $/MWh 68.85 86.13 92.95 80.30 48.32 45.90 50.44 56.92 66.79 77.58 89.15 Cost to Supply Sales $m - 411 - 520 - 568 - 497 - 303 - 291 - 323 - 369 - 439 - 516 - 600 Other Market Transactions $m 2 ------Retail Energy Margin $m 220 122 94 186 399 431 420 398 354 303 246 Financial Contracts Sold Volume GWh 1,281 1,146 1,163 1,181 1,198 1,216 1,235 1,253 1,272 1,291 1,310 Financial Contracts Sold Average Price $/MWh 61 81 88 76 47 44 49 55 64 75 86 Financil Contracts Sold Revenue $m 78.01 93.20 102.06 90.22 55.84 53.68 59.90 68.67 81.81 96.49 112.56 Acquired Generation Volume GWh 1,130 1,119 1,175 1,175 1,175 1,175 1,175 1,175 1,175 1,175 1,175 Acquired Generation Average Price $/MWh 75.81 97.59 105.29 91.70 55.91 52.96 58.22 65.76 77.19 89.70 103.08 Cost of Acquired Generation $m - 86 - 109 - 124 - 108 - 66 - 62 - 68 - 77 - 91 - 105 - 121 Net VAS Revenue $m 8 12 12 12 12 12 12 12 13 13 13 Other Market Transactions $m - 19 0 0 0 0 0 0 0 0 0 0 Derivative Contract Energy Margin $m - 19 - 4 - 9 - 5 3 4 4 4 4 4 5

NZ Energy Margin $m 939 1,060 1,031 1,024 916 928 966 1,011 1,072 1,136 1,204

Australia AUS Generation Volume GWh 519 519 519 519 519 519 519 519 519 519 519 AUS GWAP $/MWh 106 108 110 112 115 117 119 122 124 127 129 AUS Generation Energy Margin $m 55 56 57 58 60 61 62 63 64 66 67 AUS Contracted Sales $m 42 43 44 45 45 46 47 48 49 50 51 AUS Cost to Supply Contracted Sales $m - 27 - 28 - 28 - 29 - 29 - 30 - 30 - 31 - 32 - 32 - 33 AUS Contract Sales Energy Margin $m 15 15 16 16 16 17 17 17 18 18 18 AUS Energy Margin $m 70 71 73 74 76 77 79 80 82 84 85 Total Energy Margin $m 1,009 1,131 1,104 1,099 992 1,005 1,045 1,091 1,154 1,219 1,290 Generation EBIDAF NZ Generation Energy Margin $m 908 780 1,089 1,124 956 514 493 542 609 714 829 Other Revenue $m 7 6 8 8 8 8 8 8 8 9 9 Energy Transmission Expense $m - 120 - 124 - 125 - 127 - 95 - 171 - 80 - 81 - 82 - 84 - 85 Employee Expense $m - 27 - 29 - 28 - 28 - 29 - 29 - 30 - 30 - 31 - 31 - 32 Other Operating Expenses $m - 52 - 51 - 51 - 52 - 53 - 54 - 55 - 55 - 56 - 58 - 59 Total Generation/Wholesale Expenses $m - 192 - 198 - 197 - 200 - 168 - 246 - 156 - 158 - 161 - 164 - 168 NZ Generation EBITDAF $m 716 582 892 924 787 269 337 384 447 550 661 Retail EBITDAF Retail Energy Margin $m 120 220 122 94 186 399 431 420 398 354 303 Other Revenue $m 11 7 13 13 13 13 13 14 14 14 15 Employee Expense $m - 32 - 30 - 31 - 32 - 32 - 33 - 33 - 34 - 34 - 35 - 36 Electricity Metering Expense $m - 26 - 30 - 28 - 28 - 29 - 29 - 30 - 30 - 31 - 31 - 32 Other Operating Expenses $m - 32 - 31 - 32 - 32 - 33 - 33 - 34 - 34 - 35 - 36 - 36 Total Retail Expenses $m - 79 - 84 - 78 - 79 - 80 - 82 - 83 - 85 - 86 - 88 - 90 Retail EBITDAF $m 41 136 44 15 105 317 347 335 312 266 213 Unallocated and Inter-Segment Items Unallocated: Other Revenue $m 32 22 22 22 22 22 22 22 22 22 22 Employee Expense $m - 22 - 22 - 22 - 22 - 22 - 22 - 22 - 22 - 22 - 22 - 22 Other Operating Expenses $m - 22 - 20 - 24 - 25 - 25 - 25 - 26 - 26 - 27 - 27 - 28 Net Unallocated $m - 12 - 20 - 25 - 25 - 25 - 26 - 26 - 27 - 27 - 28 - 28 Intersegment: Other Revenue $m - 29 - 21 - 22 - 24 - 22 - 23 - 23 - 23 - 23 - 23 - 23 Other Expense $m 4 ------Net Inter-Segment $m - 25 - 21 - 22 - 24 - 22 - 23 - 23 - 23 - 23 - 23 - 23 Total Unallocated and Inter-Segment $m - 37 - 41 - 46 - 49 - 48 - 48 - 49 - 49 - 50 - 50 - 51

Tiwai and Derivative Trading Energy Margin $m - 128 - 62 - 151 - 186 - 117 3 4 4 4 4 4

NZ EBITDAF $m 592 616 738 704 728 540 639 674 714 770 828

International Energy Margin $m 54 70 71 73 74 76 77 79 80 82 84 Other Revenue $m - 3 ------Energy Transmission Expense $m - 3 - 4 - 4 - 4 - 4 - 4 - 4 - 4 - 4 - 5 - 5 Employee Expense $m - 7 - 11 - 11 - 11 - 12 - 12 - 12 - 12 - 12 - 13 - 13 Other Operating Expenses $m - 18 - 24 - 24 - 25 - 25 - 26 - 26 - 26 - 27 - 27 - 28 Total International Expenses $m - 28 - 36 - 39 - 40 - 41 - 41 - 42 - 43 - 44 - 45 - 45 International EBITDAF $m 26 34 32 33 34 34 35 36 37 37 38 Total EBITDAF $m 650 770 737 762 575 675 710 751 807 866 930

Income Statement (000's): Tiwai Closure 2022 As at June 30th Unit 2016 2017F 2018F 2019F 2020F 2021F 2022F 2023F 2024F 2025F 2026F NZ Generation Hydro Generation GWh 12,251 12,374 11,755 11,755 11,755 11,755 10,914 11,755 11,755 11,755 11,755 Wind Generation GWh 1,456 1,434 1,434 1,434 1,782 1,782 1,782 1,782 1,782 1,782 1,782 Total NZ Generation GWh 13,707 13,808 13,189 13,189 13,537 13,537 12,696 13,537 13,537 13,537 13,537 NZ GWAP $/MWh 56.90 79.02 87.42 103.51 107.80 78.69 38.29 40.19 47.71 55.89 65.30 NZ Generation Energy Margin $m 780 1,091 1,153 1,365 1,459 1,065 486 544 646 757 884 NZ Contracted Sales Tiwai Sales Volume GWh 5,027 4,776 4,871 4,969 5,068 5,169 - - - - - Tiwai Average Sales Price $/MWh 47.83 47.83 48.78 49.76 50.75 51.77 - - - - - Tiwai Revenue $m 240 228 238 247 257 268 - - - - - Tiwai LWAP $/MWh 56.31 78.87 87.28 103.39 107.64 78.45 - - - - - Cost to Supply Sales $m - 283 - 377 - 425 - 514 - 545 - 406 - - - - - Tiwai Energy Margin $m - 43 - 148 - 188 - 266 - 288 - 138 - - - - - Residential and SMB Sales Volume GWh 3,781 3,827 3,873 3,919 3,966 4,014 4,062 4,111 4,160 4,210 4,260 Corporate and Institutional Sales Volume GWh 2,188 2,215 2,241 2,268 2,295 2,323 2,351 2,379 2,408 2,436 2,466 Total Retail Contracted Sales Volume GWh 5,970 6,041 6,114 6,187 6,262 6,337 6,413 6,490 6,568 6,646 6,726 Retail Average Sales Price $/MWh 105.40 106.36 108.29 110.30 112.11 113.88 115.90 118.27 120.68 123.14 125.65 Retail Contracted Sales $m 629 643 662 682 702 722 743 768 793 818 845 Retail LWAP $/MWh 68.85 86.32 95.21 112.90 117.52 86.41 45.16 47.56 56.43 66.23 77.19 Cost to Supply Sales $m - 411 - 522 - 582 - 699 - 736 - 548 - 290 - 309 - 371 - 440 - 519 Other Market Transactions $m 2 ------Retail Energy Margin $m 220 121 80 - 16 - 34 174 454 459 422 378 326 Financial Contracts Sold Volume GWh 1,281 1,146 1,163 1,181 1,198 1,216 1,235 1,253 1,272 1,291 1,310 Financial Contracts Sold Average Price $/MWh 61 82 90 107 111 82 43 46 54 64 74 Financil Contracts Sold Revenue $m 78.01 93.41 104.48 126.20 133.22 99.62 53.55 57.28 69.00 82.23 97.29 Acquired Generation Volume GWh 1,130 1,119 1,175 1,175 1,175 1,175 1,175 1,175 1,175 1,175 1,175 Acquired Generation Average Price $/MWh 75.81 97.82 107.79 128.27 133.41 98.28 52.05 54.85 65.10 76.44 89.10 Cost of Acquired Generation $m - 86 - 109 - 127 - 151 - 157 - 115 - 61 - 64 - 76 - 90 - 105 Net VAS Revenue $m 8 12 12 12 12 12 12 12 13 13 13 Other Market Transactions $m - 19 0 0 0 0 0 0 0 0 0 0 Derivative Contract Energy Margin $m - 19 - 4 - 10 - 12 - 11 - 3 5 6 5 5 6

NZ Energy Margin $m 939 1,060 1,035 1,070 1,126 1,098 945 1,009 1,073 1,140 1,216

Australia AUS Generation Volume GWh 519 519 519 519 519 519 519 519 519 519 519 AUS GWAP $/MWh 106 108 110 112 115 117 119 122 124 127 129 AUS Generation Energy Margin $m 55 56 57 58 60 61 62 63 64 66 67 AUS Contracted Sales $m 42 43 44 45 45 46 47 48 49 50 51 AUS Cost to Supply Contracted Sales $m - 27 - 28 - 28 - 29 - 29 - 30 - 30 - 31 - 32 - 32 - 33 AUS Contract Sales Energy Margin $m 15 15 16 16 16 17 17 17 18 18 18 AUS Energy Margin $m 70 71 73 74 76 77 79 80 82 84 85 Total Energy Margin $m 1,009 1,131 1,108 1,145 1,202 1,175 1,024 1,089 1,155 1,224 1,301 Generation EBIDAF NZ Generation Energy Margin $m 908 780 1,091 1,153 1,365 1,459 1,065 486 544 646 757 Other Revenue $m 7 6 8 8 8 8 8 8 8 9 9 Energy Transmission Expense $m - 120 - 124 - 125 - 127 - 95 - 71 - 72 - 173 - 82 - 84 - 85 Employee Expense $m - 27 - 29 - 28 - 28 - 29 - 29 - 30 - 30 - 31 - 31 - 32 Other Operating Expenses $m - 52 - 51 - 51 - 52 - 53 - 54 - 55 - 55 - 56 - 58 - 59 Total Generation/Wholesale Expenses $m - 192 - 198 - 197 - 200 - 168 - 146 - 148 - 250 - 161 - 164 - 168 NZ Generation EBITDAF $m 716 582 894 953 1,197 1,314 917 236 383 482 589 Retail EBITDAF Retail Energy Margin $m 120 220 121 80 - 16 - 34 174 454 459 422 378 Other Revenue $m 11 7 13 13 13 13 13 14 14 14 15 Employee Expense $m - 32 - 30 - 31 - 32 - 32 - 33 - 33 - 34 - 34 - 35 - 36 Electricity Metering Expense $m - 26 - 30 - 28 - 28 - 29 - 29 - 30 - 30 - 31 - 31 - 32 Other Operating Expenses $m - 32 - 31 - 32 - 32 - 33 - 33 - 34 - 34 - 35 - 36 - 36 Total Retail Expenses $m - 79 - 84 - 78 - 79 - 80 - 82 - 83 - 85 - 86 - 88 - 90 Retail EBITDAF $m 41 136 43 1 - 97 - 116 91 369 373 334 289 Unallocated and Inter-Segment Items Unallocated: Other Revenue $m 32 22 22 22 22 22 22 22 22 22 22 Employee Expense $m - 22 - 22 - 22 - 22 - 22 - 22 - 22 - 22 - 22 - 22 - 22 Other Operating Expenses $m - 22 - 20 - 24 - 25 - 25 - 25 - 26 - 26 - 27 - 27 - 28 Net Unallocated $m - 12 - 20 - 25 - 25 - 25 - 26 - 26 - 27 - 27 - 28 - 28 Intersegment: Other Revenue $m - 29 - 21 - 22 - 24 - 22 - 23 - 23 - 23 - 23 - 23 - 23 Other Expense $m 4 ------Net Inter-Segment $m - 25 - 21 - 22 - 24 - 22 - 23 - 23 - 23 - 23 - 23 - 23 Total Unallocated and Inter-Segment $m - 37 - 41 - 46 - 49 - 48 - 48 - 49 - 49 - 50 - 50 - 51

Tiwai and Derivative Trading Energy Margin $m - 128 - 62 - 152 - 198 - 279 - 299 - 141 5 6 5 5

NZ EBITDAF $m 592 616 738 708 774 850 818 561 711 771 832

International Energy Margin $m 54 70 71 73 74 76 77 79 80 82 84 Other Revenue $m - 3 ------Energy Transmission Expense $m - 3 - 4 - 4 - 4 - 4 - 4 - 4 - 4 - 4 - 5 - 5 Employee Expense $m - 7 - 11 - 11 - 11 - 12 - 12 - 12 - 12 - 12 - 13 - 13 Other Operating Expenses $m - 18 - 24 - 24 - 25 - 25 - 26 - 26 - 26 - 27 - 27 - 28 Total International Expenses $m - 28 - 36 - 39 - 40 - 41 - 41 - 42 - 43 - 44 - 45 - 45 International EBITDAF $m 26 34 32 33 34 34 35 36 37 37 38 Total EBITDAF $m 650 771 741 808 885 853 597 748 808 870 941

Appendix L: Endnotes

i http://www.mbie.govt.nz/info-services/sectors-industries/energy/electricity-market/electricity-industry/chronology-of-new-zealand-electricity- reform/chronology-of-nz-electricity-reform.pdf ii MEL, 2016 Annual Report, page 49 (2016) iii MEL, initial offer document page 51 (2013) iv MEL, 2016 Annual 2016, page 2 (2016) v MEL, Initial Offer Document, page 53 (2013) vi MEL, 2016 Annual Report, page 41 (2016) vii MEL, 2016 Annual Report, page 11 (2016) viii MEL,2016 Annual Report, Page 4 (2016) ix MEL, 2016 Annual report, Page 86. MEL 2014 Annual Report page 68. (2016) x A World Bank Group Flagship Report, 13th Edition - Doing Business Report, 2016 ‘Measuring Regulatory Quality and Efficiency. (2016) xi ‘Genesis and Huntly Reach Agreement’ http://www.scoop.co.nz/stories/BU1604/S00826/genesis-extends-life-of-coal-fuelled-power-station- to-2022.htm (2016) xii Transpower Report, Thermal generation decommissioning from EA, 22 October, 2015. xiii ‘Otahuhu power station closure: 30 jobs affected’- http://www.nzherald.co.nz/business/news/article.cfm?c_id=3&objectid=11498485 (2015) xiv MEL, Initial Offer Document, Page 40 (2013) xv New Zealand Electricity Chronology’ http://www.mbie.govt.nz/info-services/sectors-industries/energy/electricity-market/electricity- industry/chronology-of-new-zealand-electricity-reform/chronology-of-nz-electricity-reform.pdf (2016) xvi Electricity Authority ‘Guide to Demand Modelling Paper’ -https://www.ea.govt.nz/dmsdocument/18765 xvii ‘Westpac Economic & Financial Forecasts’ – August 2016 and Statistic New Zealand Population dataset. xviii MEL Initial Offer Document, Page 44 (2013) xix Energy Markets, Policy, and Regulation – ‘Basic economics of power generation, transmission and distribution’ https://www.e- education.psu.edu/eme801/node/530 xx EA – ‘Transmission Pricing Methodology: issues and proposal’, Page 24 (2013) xxi MEL, CFO Phone interview – 30th August, 2016. xxii ‘Canstar Awards’ - http://www.canstarblue.co.nz/utilities/electricity-providers/ (2016) xxiii ‘Westpac Economic & Financial Forecasts’ – August 2016 xxiv Rio Tinto half year Annual Report (2016) xxv MEL, 2016 Annual Report, page xxvi Energy Link Price Path Report June 2016 xxvii ‘Too Busy to Mind the Business? Monitoring by Directors with Multiple Board Appointments’ – Stephen P.Ferris, Murali Jagannathan, A.C. Pritchard, (2003) xxviii EA- EMI Market trends dataset http://www.emi.ea.govt.nz/Reports/VisualChart?reportName=R_MST_C&categoryName=Retail&reportGroupIndex=2&reportDisplayContext= Gallery#reportName=R_MST_C

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