Valuation Report 2010 - Meridian Energy - Macquarie - The Crown ...

NEW ZEALAND 

Inside 

Performance evaluation 2 

Valuation summary 5 

Financial model assumptions and 

commentary 7 

Financial statements summary 15 

Financial flexibility and generation 

development 18 

Sensitivities 19 

Alternative valuation methodologies 20 

Relative disclosure 21 

Meridian Energy 

Performance evaluation 

Meridian Energy equity valuation 

Macquarie Research’s discounted cashflow-based equity valuation for Meridian 

Energy (MER) is $6,463m (nominal WACC 8.6%, asset beta 0.60, TGR 3.0%). 

We have assumed, in this estimate, that MER receives $750m for its Tekapo A 

and B assets. 

Forecast financial model 

A detailed financial model with explicit forecasts out to 2030 has been completed 

and is summarised in this report. 

Financial model assumptions and commentary 

We have assessed the sensitivity of our equity valuation to a range of inputs. 

Broadly, the sensitivities are divided into four categories: generation 

assumptions, electricity demand, financial and price path. 

We highlight and discuss a number of key model input assumptions in the report: 

• Wholesale electricity price path; 

• Electricity demand and pricing; 

• The New Zealand Aluminium Smelters (NZAS) supply contract; 

• MER’s generation development pipeline. 

Alternative valuation methodology 

• We have assessed a comparable company equity valuation for the company 

of $4,942m-$6,198m. This is based on the current earnings multiples of listed 

comparable generator/retailers globally. This valuation provides a cross-check 

of the equity valuation based on our primary methodology, discounted 

cashflow. 

• This valuation range lies below our primary valuation due, in part, to the 

recent de-rating of global renewable energy multiples (absolutely and vis-a-vis 

conventional generators). 

Relative disclosure 

• We have assessed the disclosure levels of MER’s financial reports and 

presentations over the last financial period against listed and non-listed 

companies operating in the electricity generation and energy retailing sector in 

New Zealand. 

Stephen Hudson 

+64 9 363 1414 Stephen.Hudson@macquarie.com 

This bespoke research is provided for the use of the New Zealand 

Treasury. 

1 November 2010 

Please refer to the important disclosures and analyst certification on inside back cover of this document, or on our 

website www.macquarie.com.au/research/disclosures.

Macquarie Research 


Performance evaluation 


Macquarie Research’s discounted cashflow-based equity valuation for Meridian Energy is 

$6,463m (nominal post tax WACC 8.6%, asset beta 0.60, TGR 3.0%). We have assumed, in 

this estimate, that MER will receive $750m for its Tekapo A and B assets. 

Forecast financial model 

A detailed financial model with explicit forecasts out to 2030 has been completed and is 

summarised in this report. We have used actual financial results from FY08 as a base. 

Sensitivity analysis of main valuation drivers 

We have assessed the sensitivity of our equity valuation to a range of inputs. Broadly, the 

sensitivities are divided into four categories: generation assumptions, electricity demand, 

financial and price path. 

Alternative valuation methodologies 

We have assessed a comparable company equity valuation for the company of $4,942m- 

$6,198m. This is based on the current earnings multiples of listed comparable 

generator/retailers globally. The band is based on the average multiple for selected global 

generators with a bias toward conventional generation ranging to the average multiple for 

selected global renewable generators. Macquarie has then applied a relatively arbitrary 

premium to this range to account for MER’s renewable generation bias and its pipeline of 

generation development options. 

This valuation provides a cross-check of the equity valuation based on our primary 

methodology, discounted cashflow. This valuation range lies below our primary valuation 

due, in part, to the recent de-rating of global renewable energy multiples (absolutely and visa-vis 


A sum of the parts valuation may provide another useful cross-check but is heavily dependent 

on the electricity transfer price assumed. 

Financial model assumptions and commentary 

We highlight and discuss a number of key model input assumptions in the report: 

Development pipeline. The company has proposed a number of greenfield wind and hydro 

generation developments totalling in excess of 1,300 MW in New Zealand. We have explicitly 

modelled projects which appear to have a high probability of being completed in a 1-5 year 

timeframe. For our purposes, these are Te Uku, Project Central Wind and Mill Creek. 

MER has an equity funding exposure to the Macarthur wind farm project of around A$150m 

over FY11. We have not explicitly modelled this due to limited project information. 

Retail and SME pricing. As at August 2010, Meridian Energy was pricing the energy 

component of its mass market electricity volumes at an approximate 8.4% discount to the 

average market pricing – up from an approximate 2.9% discount a year ago. 

We have attempted to back out Meridian Energy’s commercial/SME fixed pricing by 

calculating the commercial/SME pricing discount seen in historical periods (based on pricing 

information from the MED). We assume a 15% discount in pricing our forecasts. 

NZAS supply contract renewal and pricing. We have incorporated our interpretation of MER’s 

New Zealand Aluminium Smelters (NZAS) contract volumes and pricing into our forecasts. 

Essentially, 572 MW (continuous) is priced from January 2013 at a base price around 10% 

higher than the base price (i.e., energy only) under the existing supply contract. This base 

price is subject to escalation with reference to a multi-year average NZ electricity market 

price, the world price for aluminium, and a component as a proxy for price inflation. 

1 November 2010 2



Fig 1 

NZAS historical power price 

31/12/2009 31/12/2008 31/12/2007 31/12/2006 

NZAS power purchases $292.7m $310.1m $299.9m $276.1m 

Power usage 576 MW 413 MW 608 MW 604 MW 

Implied cost / MWh – energy only 5.8c/kWh 8.6c/kWh 5.6c/kWh 5.2c/kWh 

Source: Macquarie Research, October 2010 

Source: NZAS Annual Report, December 2009 

Wholesale electricity price paths. We have adjusted our wholesale electricity price forecast 

since the last MER performance evaluation report – Meridian Energy: Performance 

Evaluation (published 5 October 2009) - see below graph. 

Based on expected demand and supply (taking into account future projects coming online), 

we continue to expect the wholesale electricity price to approach the LRMC of wind 

generation by 2020 (the year in which other, cheaper, generation alternatives have been 

exhausted). We think new thermal generation capacity will be limited (beyond Contact’s 

Taranaki peakers) due to difficulties in obtaining adequate gas supply and to the availability of 

cheaper geothermal development options. We estimate the current LRMC of wind at 

$100/MWh (2010$). We note, however, that this LRMC is highly sensitive to currency, turbine 

pricing and cost of capital assumptions. 

The price paths have been updated to reflect expected weakness in wholesale prices over 

the next two years, primarily due to lower expected load growth. We assess the impact of the 

EIA reforms on pricing and volume later in this report. 

Fig 2 Wholesale and retail electricity price path forecasts 

$NZ 

300.0 

Wholesale electricity price FY10 ($/MWh) 

Wholesale electricity price FY09 ($/MWh) 

Retail electricity price FY10 (c/kWh) 

Retail electricity price FY09 (c/kWh) 

250.0 

200.0 

150.0 

100.0 

50.0 

- 

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 


We recognise that the rate of growth in the retail price path falls short of that of wholesale 

prices as currently modelled and, as such, is conservatively struck. 

Electricity Industry Act. Macquarie Securities has attempted to capture the impact of the 

physical and virtual asset swaps (VAS) impact contained in the legislation. 

We have assumed a three-year progressive ramp-up for the Meridian Energy-GEN swap to 

an ultimate volume of 450 GWh. We have assumed a three-year progressive ramp-up to the 

Meridian Energy-MRP ultimate swap volume of 700 GWh. 

The Tekapo A and B transfer is assumed to be effective 1 November 2010 and priced at the 

mid-point of the valuation range indicated in the Office of the Minister of Energy and 

Resources cabinet paper dated 9 December 2009 (i.e., $700m-800m). 

We have stepped down our TOU, SME and mass market volumes proportionately for FY11- 

13 to reflect the Tekapo A and B station mean output (de-rated for a ‘very-dry’ year). 




The VAS contracts are assumed to be priced at fair value. 

Fig 3 Meridian Energy summary financials (MER: $4.04) 

Profit & Loss 2009A 2010A 2011E 2012E 

Operating Revenue $m 1892 2062 2108 2121 

EBITDAF $m 512 642 628 599 

Depreciation $m (150) (174) (188) (185) 

Amortisation $m (13) (14) 0 0 

EBIT - Recurring $m 361 465 441 413 

EBIT $m 229 386 441 413 

Net Interest Expense $m (101) (108) (119) (86) 

Pre-Taxation Profit $m 128 277 322 327 

Taxation Expense $m (39) (93) (95) (92) 

Profit after Taxation $m 89 184 227 235 

Adjustments after income tax $m 132 80 0 0 

expense 

Adjusted Earnings 1 $m 221 264 227 235 

1. Adjusted for significant one-off items and the change in the fair value of financial instruments 

Key Assumptions 

GWAP $/MWh 46.0 52.2 59.3 59.9 

Total generation GWh 12,237 13,862 13,216 13,005 

LWAP/GWAP x 1.33 1.22 1.18 1.18 

FPVV GWh 1,810 1,747 1,623 1,563 

Retail electricity price growth % 4.42% 2.62% 2.00% 2.00% 

Discounted Cashflow Valuation Profit and Loss Ratios 2009A 2010A 2011E 2012E 

PER (adj Earnings) x 29.2 24.5 28.5 27.5 

PV FCFs Available to Owners $m 6,976 EPS (adj Earnings) c 29.2 24.5 28.5 27.5 

Plus: Book Value of international $m 260 EPS (Reported) c 5.6 11.5 14.2 14.7 

assets 

Plus: Special dividend from sale of $m 750 DPS c 1.9 22.1 34.8 11.8 

Tekapo 

Receivable $m 30 Revenue Growth % (27.2%) 9.0% 2.2% 0.6% 

Less Net Debt $m (1,553) EBIT Growth % (14.3%) 68.5% 14.3% (6.3%) 

Equity Value $m 6,463 EBITDAF/Sales % 27.1% 31.1% 29.8% 28.2% 

Shares Outstanding m 1,600 EBIT/Sales % 12.1% 18.7% 20.9% 19.5% 

Equity Value per Share $ 4.04 Effective tax rate % 30.2% 33.6% 29.5% 28.0% 

Payout ratio % 13.6% 134.0% 245.4% 80.0% 

Assumptions EV/EBIT x 34.9 20.7 18.1 19.3 

Risk Free Rate % 5.50% EV/EBITDA x 15.6 12.4 12.7 13.3 

Asset Beta # 0.60 EV/Revenue x 4.2 3.9 3.8 3.8 

Market Risk Premium % 7.0% 

Target Debt/Value % 20.0% Balance Sheet Ratios 

Nominal Post-Tax WACC % 8.56% ROE % 5% 5% 5% 5% 

Perpetuity Growth Rate % 3.0% ROA % 5% 5% 6% 5% 

ROFE % 7% 7% 8% 7% 

Net Debt $m 1,204 1,553 1,103 1,117 

Net Debt/Equity % 28% 31% 23% 23% 

Net Interest Cover (EBIT) x 4 4 4 5 

Price/NTA x 0.9 0.7 0.8 0.8 

NTA per share cps 446 542 492 496 

EFPOWA m 1,600 1,600 1,600 1,600 

Cashflow Analysis 2009A 2010A 2011E 2012E Balance Sheet 2009A 2010A 2011E 2012E 

Pre-taxation Profit $m 128 277 322 327 Cash $m 48 54 - - 

Depreciation & Amortisation $m 150 174 188 185 Receivables $m 188 199 204 205 

Tax (Paid)/Credit $m (31) (93) (95) (92) Inventories $m 7 6 6 6 

Other $m 123 83 - - Investments accounted for using $m 2 0 0 0 

equity method 

Gross Cashflow $m 370 441 414 421 Property, Plant & Equipment $m 6,743 8,207 7,458 7,519 

Changes in Working Capital $m (57) 10 (0) (0) Intangibles $m 44 50 50 50 

Changes in Provisions $m - - 0 0 Derivative Financial Instruments $m 127 183 183 183 

Operating Cashflow $m 314 452 414 421 Other Assets $m 18 15 15 15 

Acquisitions/Investments $m (16) (263) - - Total Assets $m 7,177 8,716 7,917 7,978 

Capital Expenditure $m (484) (207) (188) (246) Payables $m 170 202 206 207 

Asset Sales $m 24 12 750 - Short Term Debt $m 123 284 284 284 

Other $m - - 30 - Long Term Debt $m 1,129 1,323 819 833 

Investing Cashflow $m (477) (458) 592 (246) Derivative Financial Instruments $m 140 191 191 191 

Dividend (ordinary) $m (30) (353) (556) (188) Other Liabilities $m 1,331 1,592 1,592 1,592 

Debt drawndown / (repayment) $m 169 367 (504) 14 Total Liabilities $m 2,893 3,645 3,145 3,160 

Other $m - - - - Shareholders' Funds $m 1,600 1,600 1,600 1,600 

Financing Cashflow $m 139 13 (1,060) (175) Retained Earnings $m (51) (216) (516) (469) 

Total Shareholders' Equity $m 4,284 5,071 4,771 4,818 

Net Change in Cash (inc FX) $m (24) 7 (54) - Total Funds Employed $m 7,177 8,716 7,917 7,978 

Source: Company data, Macquarie Research, October 2010 




Valuation summary 


Fig 4 Meridian Energy DCF equity valuation summary 

Perpetuity growth rate 3.00% 

Perpetuity Value 11,381 

PV (FY10-29) 4,382 

PV of Perpetuity 2,594 

PV FCF available to owners 6,976 

Plus: book value of international assets 260 

Plus: special dividend from sale of Tekapo 750 

Plus: Receivable 30 

Less Net Debt (1,553) 

Equity Value 6,463 

Shares Outstanding (m) 1,600 

DCF Equity Value per share 4.04 

Assumptions 

Corporate Tax Rate 28% 

Risk free rate 5.50% 

Asset beta 0.60 

Equity beta 0.75 

Market Risk Premium 7.0% 

Target Debt/Venture 20% 

Target Equity/Venture 80% 

Cost of Debt 8.25% 

Tax-adjusted Cost of Debt 5.94% 

Ungeared Cost of Equity 7.37% 

Cost of Equity 9.21% 

Nominal WACC (%) 8.56% 


We have summarised our DCF-based equity valuation ($6,463m) for Meridian Energy 

(above) and key sensitivities (below). The valuation summary includes the discount rate and 

terminal growth assumptions (nominal post tax WACC 8.6%, asset beta 0.6, TGR 3.0%). 

Risk free rate. We have estimated the risk free rate using the yield of the 10 Year New 

Zealand Government Bond rate as an approximation. A 6 month average yield was used to 

prevent any distortion arising from shocks in the spot rate. The risk free rate estimated as at 

1st October 2010 was 5.50%. 

Selection of MRP. We have used a post investor tax market risk premium of 7%, consistent 

with the estimation Macquarie Research uses for other New Zealand listed companies. 

Long term gearing. We have assumed an appropriate long term gearing level for the 

calculation of a discount rate based on the company’s published targets (where available) 

and historical levels of gearing. 

Asset betas. We have estimated the asset beta of the company through comparable 

company analysis. The asset beta approximation was calculated by taking an average of the 

unlevered asset betas of appropriate listed companies with similar business operations. 




Fig 5 Sensitivities 

5,000 5,500 6,000 6,500 7,000 7,500 8,000 

Capacity factors 

(-/+ 1%) 

6,211 

6,715 

Carbon cost 

($25/t /$0/t) 

Wholesale electricity prices 

(-/+ $10MWh) 

6,470 

6,391 

6,568 

6,549 

Retail electricity prices 

(-/+ 0.5c/kWh) 

6,163 

6,763 

Customer growth 

(+/- 0.1%) 

Usage per customer 

(-/+ 500kWh pa) 

Debt margin 

(+/- 0.5%) 

6,459 

6,439 

6,375 

6,467 

6,487 

6,553 

Market risk premium 

(+/- 0.5%) 

6,112 

6,853 

LWAP 

(+/- 1% point) 

6,370 

6,556 

NZAS base price escalation 

(+/- 1% point) 

6,152 

6,815 

Maintenance capex cost inflation 

(+/- 0.5% point) 

6,326 

6,590 

Greenfield development timing1 

(+/- 1 year) 

6,159 

6,363 





Financial model assumptions and 

commentary 

(i) Wholesale electricity price path scenarios and carbon pricing 

We have reconstructed our wholesale electricity price forecast since the last report in 2008. 

Based on expected demand and supply (taking into account future projects coming online), 

we think that the wholesale electricity price will approach the LRMC of wind generation by 

2020 (the year in which other, cheaper, generation alternatives would be exhausted). We do 

not think new thermal generation will be built in the foreseeable future (beyond Contact’s 

Taranaki peakers) due to difficulties in obtaining adequate gas supply arrangements. We 

estimate the current LRMC of wind at $100/MWh (2009 dollars). We note, however, that this 

LRMC is highly sensitive to currency, turbine pricing and cost of capital assumptions. 

Our wholesale price path includes a carbon tax of $15/tonne CO 2 e from July 2011. We 

assume the company has no carbon liability (by virtue of its renewable generation base) and 

that it receives no carbon credits from the government. This is broadly consistent with the 

recently enacted emissions trading scheme bill. 

(ii) Electricity demand and retail pricing 

We analyse Meridian’s electricity demand by examining several customer categories: 

• Mass market customers; 

• Fixed price SMEs: small commercial and industrial (C&I) customers that pay a fixed price 

rate; 

• TOU customers: this category includes large C&I customers that pay spot prices fixed, 

typically, for 1-3 years; and 

• NZAS: electricity either physically delivered, or hedged by CFD, to NZAS. 

Mass market customers 

Volume 

We have analysed the Ministry of Economic Development’s quarterly mass market electricity 

pricing data for each retailer. We have separated out the impact on retail pricing from 

changes to lines charges. We have done this to enable a comparison of the net retail margin 

for each retailer. 

The company has an approximate 9% market share in the electricity mass market. The 

company’s market share has been relatively constant over recent years. 

We assume the company will maintain its market share, with total national ICP growth of 

0.9% pa forecast. Predicted usage per user is assumed to be constant at 8,000 kWh pa. 

Note, historical 10-year and 25-year mass market volume growth has averaged 1.6% pa (i.e., 

for both periods). 

Pricing 

As at August 2010, Meridian Energy was pricing the energy component of its mass market 

electricity volumes at an approximate 8.4% discount to the average market pricing – up from 

an approximate 2.9% discount a year ago. 

For FY11 and FY12, we assume a 2% nominal increase in MER’s mass market pricing – 

close to the level of price increases expected across key competitors. We assume a return to 

more normal price increases after FY12, with 2.5% pa price growth. 




Transmission and distribution costs are modelled to grow by CPI – X pa (as per the current 

thresholds regime for distribution companies), where X represents the current weighted 

average X factor for distribution companies, or for Transpower. 

We have assumed the same retail price path for all retailers (adjusting for current relative 

pricing levels). 

Fixed price SME and TOU volumes 

Volume 

Fixed price SME and TOU volumes have been estimated on an historical basis. From FY16 

onwards, fixed price SME volumes are assumed to grow at 3.0% pa. Historical 10-year and 

35-year SME volume growth rates have averaged 3.8% pa and 3.2% pa, respectively. 

Total sales are constrained by the 1:20 dry-year production variance we estimate across 

Meridian Energy’s hydro systems, and we adjust TOU volumes to meet this constraint. Note 

that historical 10-year and 35-year industrial volume growth rates have averaged -0.4% pa 

and 2.5% pa, respectively. 

Pricing 

We have attempted to back out Meridian Energy’s SME fixed pricing by calculating the pricing 

discount to market prices seen in historical periods (based on whole of market pricing 

information from the MED). We have assumed a 15% price discount in our forecasts. 

GWAP / LWAP factor 

There are systemic differences between generation prices achieved and load prices paid due 

to transmission constraints, geographical separation of generation and load centres, and the 

ability to control generation output relative to timing of load demand. 

These differences can be separated into a Generation Weighted Average Price (GWAP) 

factor and Load Weighted Average Price (LWAP) factor. Each factor is referenced to a 

benchmark pricing node and represents the premium or discount to the benchmark price 

received for generation (GWAP), or paid for supplying load (LWAP) relative to the benchmark 

node. 

We have forecast a GWAP and LWAP for Meridian Energy based on historical analysis and 

the outlook for transmission constraints and demand growth. This factor is applied to our 

benchmark wholesale price path to generation earnings and retailing costs. 

Fig 6 Wholesale and retail electricity price path forecasts 

FY10A FY11E FY12E FY13E FY14E FY15E FY16E FY17E FY18E FY19E FY20E 

30/06/10 30/06/11 30/06/12 30/06/13 30/06/14 30/06/15 30/06/16 30/06/17 30/06/18 30/06/19 30/06/20 

Wholesale electricity price $MWh 59.0 65.2 65.8 71.6 77.6 85.5 94.4 104.3 115.5 127.9 130.7 

% change in wholesale electricity price % p.a. 1.16% 10.51% 0.91% 8.84% 8.33% 10.23% 10.39% 10.54% 10.67% 10.80% 2.14% 

Retail electricity price c/kWh 20.8 21.2 21.6 22.2 22.7 23.3 23.9 24.5 25.1 25.7 26.4 

% change in retail electricity price % p.a. 2.62% 2.00% 2.00% 2.50% 2.50% 2.50% 2.50% 2.50% 2.50% 2.50% 2.50% 





Fig 7 Meridian Energy - Retail 


30/06/10 30/06/11 30/06/12 30/06/13 30/06/14 30/06/15 30/06/16 30/06/17 30/06/18 30/06/19 30/06/20 

Customers - electricity 

Retail customers # 185,262 172,665 167,117 168,454 169,987 171,534 173,095 174,670 176,260 177,864 179,482 

Usage per user (annualised kWh) kWh 9,429 9,400 9,350 9,300 9,250 9,200 9,150 9,150 9,150 9,150 9,150 

Retail volume GWh 1,747 1,623 1,563 1,567 1,572 1,578 1,584 1,598 1,613 1,627 1,642 

Losses GWh 121 113 109 109 109 110 110 111 112 113 114 

Other FPVV/SME volume GWh 4,076 3,851 3,773 3,841 3,921 4,026 4,147 4,271 4,399 4,531 4,667 

Losses GWh 170 160 157 160 163 168 173 178 183 189 194 

Total retail sales GWh 5,823 5,474 5,335 5,407 5,494 5,604 5,730 5,869 6,012 6,159 6,309 

Losses GWh 291 273 266 269 273 277 283 289 295 302 309 

Total GWh 6,114 5,747 5,601 5,676 5,766 5,881 6,013 6,158 6,307 6,460 6,618 

Wholesale volumes 

TOU sales GWh 1,835 1,720 1,664 1,665 1,667 1,669 1,670 1,672 1,674 1,675 1,677 

Losses GWh 128 120 116 116 116 116 116 116 116 116 117 

Total GWh 1,963 1,840 1,779 1,781 1,783 1,785 1,786 1,788 1,790 1,792 1,793 

Pricing - electricity 

Retail electricity price path 

% change in retail electricity price % p.a. 2.6% 2.0% 2.0% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 

Retail electricity price c/kWh 20.8 21.2 21.6 22.2 22.7 23.3 23.9 24.5 25.1 25.7 26.4 

Retail prices 

Change in retail price component % 1.7% 1.4% 0.8% 2.7% 2.7% 2.7% 2.7% 2.7% 2.6% 2.6% 2.6% 

Energy component c/kWh 13 13 13 13 14 14 14 15 15 16 16 

Change in distribution price component % 4.1% 3.1% 4.0% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 2.5% 

Distribution component c/kWh 6 6 7 7 7 7 7 7 8 8 8 

Change in transmission price component % 4.2% 2.1% 3.0% 1.5% 1.5% 1.5% 1.5% 1.5% 1.5% 1.5% 1.5% 

Transmission component c/kWh 2 2 2 2 2 2 2 2 2 2 2 

SMEs - discount to market % (15.0%) (15.0%) (15.0%) (15.0%) (15.0%) (15.0%) (15.0%) (15.0%) (15.0%) (15.0%) (15.0%) 

SMEs c/kWh 11 11 11 11 12 12 12 13 13 13 14 

Lines charge - SMEs c/kWh 4 4 4 4 5 5 5 5 5 5 5 

TOU (Spot) price path 

Wholesale price $/MWh 59 65 66 72 78 85 94 104 115 128 131 

LWAP benefit (cost) % 108.4% 107.0% 107.0% 107.0% 107.0% 107.0% 107.0% 107.0% 107.0% 107.0% 107.0% 

Electricity Price $/MWh 64 70 70 77 83 91 101 112 124 137 140 


Fig 8 Meridian Energy - Operations 


30/06/10 30/06/11 30/06/12 30/06/13 30/06/14 30/06/15 30/06/16 30/06/17 30/06/18 30/06/19 30/06/20 

Revenue 

Generation 960 1,021 1,044 1,123 1,239 1,373 1,489 1,629 1,785 1,959 2,002 

Retail 1,086 1,047 1,035 1,080 1,130 1,188 1,252 1,322 1,398 1,478 1,544 

Energy related services revenue 16 17 18 19 20 20 21 22 23 24 25 

Other revenue 22 23 24 25 25 26 26 27 28 28 29 

2,085 2,108 2,121 2,246 2,413 2,607 2,788 3,000 3,234 3,490 3,600 

Expenses 

Electricity expense (792) (834) (862) (935) (1,011) (1,125) (1,256) (1,405) (1,573) (1,764) (1,824) 

Carbon charge - - - - - - - - - - - 

Transmission and distribution expense (280) (281) (283) (293) (304) (316) (329) (344) (360) (376) (393) 

Employee costs (87) (91) (97) (100) (104) (108) (112) (116) (121) (125) (130) 

Cost to serve (29) (41) (42) (43) (45) (46) (48) (49) (51) (53) (55) 

O&M from new wind generation - - (2) (6) (12) (16) (17) (17) (18) (19) (20) 

Other operating expenses (134) (121) (128) (133) (138) (143) (148) (154) (160) (166) (172) 

(1,439) (1,480) (1,523) (1,622) (1,727) (1,870) (2,025) (2,201) (2,398) (2,619) (2,710) 

EBITDA 645 628 599 625 686 737 763 799 835 871 891 

Depreciation and Amortisation (174) (188) (185) (206) (237) (256) (259) (261) (264) (267) (270) 

EBIT 471 441 413 419 450 481 504 538 571 604 621 





(iii) NZAS and long-term contract hedges – pricing and volume 

We have incorporated our interpretation of MER’s New Zealand Aluminium Smelters (NZAS) 

contract volumes and pricing into our forecasts. 

Essentially, 572 MW (continuous) is priced from January 2013 at a base price around 10% 

higher than the base price (i.e., energy only) under the existing supply contract. This base 

price is subject to escalation with reference to a multi-year average NZ electricity market 

price, the world price for aluminium, and a component as a proxy for price inflation. 

The base price for the current NZAS contract, which expires at the end of 2012, is believed to 

currently be ~5.5c/kWh (normalised for the impact of the NZAS transformer failure). It is 

assumed this will increase at CPI until the end of the contract. 

NZAS had claimed force majeure for an NZAS transformer failure which occurred in 

November 2008. This outage resulted in the use of electricity below the take or pay level. 

NZAS has estimated the value difference between the full take or pay contracted amount and 

actual usage at approximately $57m as at 31 December 2009. 

Meridian Energy and New Zealand Aluminium Smelters (NZAS) announced recently that they 

reached a negotiated and confidential settlement of arbitration proceedings concerning 

liability payment for electricity. Macquarie Securities has made an allowance for a receivable 

in our forecasts and equity valuation. 

(iv) Generation assets 

The financial model sets out Meridian Energy’s generation assets by plant and region. 

Development projects are not included in the financial projections unless they are sufficiently 

certain (see below). Our generation output forecasts are driven by assumed availability and 

capacity factors. Wind capacity factors for new projects are conservatively estimated at 

around 39%. 

We assume mean hydrology conditions and existing operating level limits at both the country 

and company level. We do not specifically forecast major maintenance downtime into plant 

availability factors, but instead assume a smoothed maintenance profile (i.e., average life 

cycle availability factors). 

Development pipeline 

The company has proposed a number of greenfield generation developments (see below). 

Only those that we have assessed as likely to be developed with sufficient certainty are 

included in our financial model and DCF-based equity valuation. Non-modelled projects cover 

a range of projects at various stages of development. These projects will have option value 

for the company, but we have not attempted to quantify this value. 

Fig 9 Meridian Energy generation pipeline 

Project Type Size (MW) Estimated cost ($m) Completion date 

Modelled projects 

Te Uku Wind 64 247 2H12 

Project Central Wind Wind 120 340 2H14 

Mill Creek Wind 67 228 2H13 

Non-modelled projects 

Project Hayes Wind 630 ~2,000 ? 

North Bank Tunnel Hydro 220-280 700-900 ? 

Mokihinui Hydro 85 ? ? 

Hurunui Wind Wind 120 ? ? 

Hunter Downs Irrigation Wind ? ? ? 

MacArthur (Australia) Wind 420 ? ? 

Mt Mercer (Australia) Wind 130 ? ? 

Source: Meridian Energy, Press, Standard & Poor’s, October 2010 




(v) Electricity Industry Act 

Key assumptions 

On 23 September, the Electricity Industry Bill passed through Parliament. 

The Act implements the final decisions of Government following the 2009 Ministerial review of 

the sector. 

The legislation which came into force on 1 October 2010 is focused on improving competition 

in the industry, promoting reliability of electricity supply and improving governance in the 

sector through the establishment of the Electricity Authority. 

The key components of the legislation and its impact are summarised below. 

• Asset and virtual asset swaps between all three SOE gentailers to effect greater fuel and 

geographic diversity across generation portfolios. The ultimate objective in this regard is to 

promote nation-wide retail electricity competition, particularly in the South Island; 

• Allowing lines businesses back into retailing subject to certain controls; 

• Establishment of a liquid hedge market so that generators and retailers, especially new 

entrants, and businesses generally, can better manage volatile spot prices; 

• Reducing barriers to retail entry by reducing the complexity of line tariffs; and 

• Establishing a fund to encourage consumers to discover and react to relative pricing. 

Fig 10 Illustrative impact of EIB on mass market shares - 15% South Island mass 

market turned over; 3% of North Island 

Mean 

output 

(GWh) 

Mighty River 

Power 5 

Nth Isl 

(ICPs) 

Sth Isl 

(ICPs) 

Genesis 

Energy 6 

Nth Isl 

(ICPs) 

Sth Isl 

(ICPs) 

Meridian 

Energy 7 

Nth Isl 

(ICPs) 

Sth Isl 

(ICPs) 

Non-SOEs 

Nth Isl 

(ICPs) 

Sth Isl 

(ICPs) 

Pre-swap mass market ICPs 4 407864 33643 513449 15171 95255 150247 442702 321521 

Pre-swap mass market share 5 28% 6% 35% 3% 7% 29% 30% 62% 

Physical asset swaps 

1. Tekapo A and B to GEN from MER 1000/700 1 28824 -28824 

2. Whirinaki assignment 0 

Virtual asset swaps 3 

1. MER-GEN 450 -19688 18529 19688 -18529 

2. MER-MRP 700 -30625 28824 30625 -28824 

Mass market customer switches -30625 28824 -19688 47353 50313 -76176 0 0 

Post-swap mass market share 5 26% 12% 34% 12% 10% 14% 30% 62% 

Total North Island churn 3% 

Total South Island churn 15% 

1. Mean output of Tekapo stations de-rated by 30% to account for 'very-dry' year variation 

2. Assume Sth Isl retail customers average consumption 8,500 KWh; Nth Isl 8,000 KWh. TOU and SME market assumed to 

bear 65% of switching. 

3. Assume 15 year duration; impact is post 3 year ramp-up 

4. As at August 2010 

5. Includes Bosco 

6. Includes Energy Online 

7. Includes Powershop; excludes Energy Direct ICPs 


Macquarie Securities has attempted to capture the impact of the physical and virtual asset 

swaps (VAS) impact contained in the legislation. 

We have assumed a three-year progressive ramp-up for the Meridian Energy-GEN swap to 

an ultimate volume of 450 GWh. We have assumed a three-year progressive ramp-up to the 

Meridian Energy-MRP ultimate swap volume of 700 GWh. 

The Tekapo A and B transfer is assumed to be effective 1 November 2010 and priced at the 

mid-point of the valuation range indicated in the Office of the Minister of Energy and 

Resources cabinet paper dated 9 December 2009 (i.e., $700m-800m). 




We note that Genesis Energy appears to have predicated its retail market strategy based on 

its post EIB position, and some pricing and volume effects have already occurred. By way of 

example, GEN’s respective pricing in Dunedin, Invercargill and across the Otagonet network 

is around 20%, 8% and 17% lower than incumbent pricing. We note that non-SOE 

companies are incumbent retailers in these regions. 

We have stepped down our TOU, SME and mass market volumes proportionately over FY11- 

13 to reflect the Tekapo A and B station mean output (de-rated for a ‘very-dry’ year). 

The VAS contracts are assumed to be priced at fair value. 

Other EIB changes 

The legislation also introduces measures aimed at improving security of electricity supply. 

These include: 

• The removal of the reserve energy scheme put in place in 2003 and ensuring that the 

Whirinaki power station is operated commercially; 

• The introduction of a requirement on retailers to compensate consumers when public 

conservation campaigns are put in place; 

• Additionally, there is provision for a floor to be applied to spot prices during campaigns and 

other supply emergencies. 

On industry governance, the legislation replaces the Electricity Commission with an 

independent Electricity Authority focused on enforcing and developing electricity market rules 

and contracting for key market operation services. 

Macquarie Securities has not attempted to model any changes resulting from these 

provisions. 




Fig 11 Meridian Energy generation assets 


30/06/10 30/06/11 30/06/12 30/06/13 30/06/14 30/06/15 30/06/16 30/06/17 30/06/18 30/06/19 30/06/20 

Tekapo 

Annual station capacity MW 185 62 - - - - - - - - - 

Availability factor % 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 

Potential supply GWh 1,621 540 - - - - - - - - - 

Capacity factor % 59.8% 59.8% -% -% -% -% -% -% -% -% -% 

Nominal annual generation GWh 969 323 - - - - - - - - - 

Ohau 

Annual station capacity MW 688 688 688 688 688 688 688 688 688 688 688 


Potential supply GWh 6,027 6,027 6,027 6,027 6,027 6,027 6,027 6,027 6,027 6,027 6,027 

Capacity factor % 50.1% 50.1% 50.1% 50.1% 50.1% 50.1% 50.1% 50.1% 50.1% 50.1% 50.1% 

Nominal annual generation GWh 3,022 3,022 3,022 3,022 3,022 3,022 3,022 3,022 3,022 3,022 3,022 

Benmore 






Aviemore 





Nominal annual generation GWh 948 948 948 948 948 948 948 948 948 948 948 

Waitaki 



Potential supply GWh 788 788 788 788 788 788 788 788 788 788 788 



Manapouri 






Total Hydro Capacity MW 2,453 2,330 2,268 2,268 2,268 2,268 2,268 2,268 2,268 2,268 2,268 

Total Hydro Generation GWh 12,857 12,211 11,888 11,888 11,888 11,888 11,888 11,888 11,888 11,888 11,888 

Wind Generation 

Te Apiti 






Project White Hill 






West Wind - Wellington 






Te Uku 

Annual station capacity MW - - 64 64 64 64 64 64 64 64 64 

Availability factor % -% -% 50.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 

Potential supply GWh - - 280 561 561 561 561 561 561 561 561 

Capacity factor % -% -% 40.0% 40.0% 40.0% 40.0% 40.0% 40.0% 40.0% 40.0% 40.0% 

Nominal annual generation GWh - - 112 224 224 224 224 224 224 224 224 

Project Central Wind 

Annual station capacity MW - - - - 120 120 120 120 120 120 120 

Availability factor % -% -% -% -% 50.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 

Potential supply GWh - - - - 526 1,051 1,051 1,051 1,051 1,051 1,051 

Capacity factor % -% -% -% -% 38.5% 38.5% 38.5% 38.5% 38.5% 38.5% 38.5% 

Nominal annual generation GWh - - - - 202 405 405 405 405 405 405 

Mill Creek 

Annual station capacity MW - - - 67 67 67 67 67 67 67 67 

Availability factor % -% -% -% 50.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 

Potential supply GWh - - - 293 587 587 587 587 587 587 587 

Capacity factor % -% -% -% 38.5% 38.5% 38.5% 38.5% 38.5% 38.5% 38.5% 38.5% 

Nominal annual generation GWh - - - 113 226 226 226 226 226 226 226 

Total Wind Capacity MW 291 291 355 422 542 542 542 542 542 542 542 

Total Wind Generation GWh 1,005 1,005 1,117 1,342 1,658 1,860 1,860 1,860 1,860 1,860 1,860 

Total Capacity MW 2,744 2,621 2,623 2,690 2,810 2,810 2,810 2,810 2,810 2,810 2,810 

Total Generation GWh 13,862 13,216 13,005 13,230 13,546 13,748 13,748 13,748 13,748 13,748 13,748 





(v) Other 

Arc Innovations 

We have not explicitly modelled the Arc Innovations business due to its materiality to the 

MER equity valuation and availability of information. 

WhisperTech, WhisperGen and Energy for Industry 

We have not explicitly modelled the WhisperTech and WhisperGen CHP businesses or the 

Energy for Industry subsidiary, due to their materiality to the valuation and availability of 

information. 

Mt Millar wind farm 

The Mt Millar wind farm is included in the MER equity valuation as an ‘international asset’ at 

its estimated book value. 

US solar 

The US solar assets are included in the MER equity valuation as an ‘international asset’ at 

their estimated book value. 

IFRS 

Under IFRS, Meridian must mark-to-market the expected cashflows under its new contract 

with NZAS. We have not modelled any future marking-to-market, consistent with modelling 

the expected cashflows (EBITDAF) under the contract. 

Non-recurring operating costs 

Macquarie Research estimates that there were approximately $20m of non-recurring 

operating costs incurred by MER over FY10. These were largely related to acquisition activity, 

head office cost rationalisation and legislation-related costs. We have re-based our forecasts 

accordingly. 




Financial statements summary 

Fig 12 Meridian Energy income statement ($NZm) 


30/06/10 30/06/11 30/06/12 30/06/13 30/06/14 30/06/15 30/06/16 30/06/17 30/06/18 30/06/19 30/06/20 

Revenue $m 2,062 2,108 2,121 2,246 2,413 2,607 2,788 3,000 3,234 3,490 3,600 

Operating Expenses $m (1,420) (1,480) (1,523) (1,622) (1,727) (1,870) (2,025) (2,201) (2,398) (2,619) (2,710) 

EBITDAF $m 642 628 599 625 686 737 763 799 835 871 891 

Depreciation $m (174) (188) (185) (206) (237) (256) (259) (261) (264) (267) (270) 

Goodwill amortisation $m (14) - - - - - - - - - - 

EBIT - Recurring $m 465 441 413 419 450 481 504 538 571 604 621 

EBIT - Non-Recurring $m (80) - - - - - - - - - - 

Total EBIT $m 386 441 413 419 450 481 504 538 571 604 621 

Net Interest Expense $m (108) (119) (86) (90) (98) (113) (97) (81) (63) (45) (28) 

NPBT $m 277 322 327 329 352 367 406 457 508 558 593 

Taxation Expense/ (Credit) $m (93) (95) (92) (92) (99) (103) (114) (128) (142) (156) (166) 

NPAT $m 184 227 235 237 253 265 293 329 366 402 427 

Adjustments after income tax expense $m 80 - - - - - - - - - - 

Adjusted NPAT $m 264 227 235 237 253 265 293 329 366 402 427 

EFPO and Ratios 

Shares on issue m 1600 1600 1600 1600 1600 1600 1600 1600 1600 1600 1600 

Revenue 2,062 2,108 2,121 2,246 2,413 2,607 2,788 3,000 3,234 3,490 3,600 

EBITDAF $m 642 628 599 625 686 737 763 799 835 871 891 

EBIT - Recurring $m 465 441 413 419 450 481 504 538 571 604 621 

EPS c 11.5 14.2 14.7 14.8 15.8 16.5 18.3 20.6 22.9 25.1 26.7 

EPS (adjusted) c 16.5 14.2 14.7 14.8 15.8 16.5 18.3 20.6 22.9 25.1 26.7 

CFPS c 27.6 25.9 26.3 27.7 30.6 32.6 34.5 36.9 39.4 41.8 43.5 

EBITDAF margin % 31.1% 29.8% 28.2% 27.8% 28.4% 28.3% 27.4% 26.6% 25.8% 25.0% 24.7% 

EBIT margin % 18.7% 20.9% 19.5% 18.6% 18.6% 18.4% 18.1% 17.9% 17.7% 17.3% 17.2% 

EV/Revenue x 3.9 3.8 3.8 3.6 3.3 3.1 2.9 2.7 2.5 2.3 2.2 

EV/EBITDAF x 12.4 12.7 13.3 12.8 11.6 10.8 10.5 10.0 9.6 9.2 9.0 

EV/EBIT x 20.7 18.1 19.3 19.1 17.8 16.6 15.9 14.9 14.0 13.2 12.9 

PER x 35.1 28.5 27.5 27.3 25.5 24.4 22.1 19.6 17.7 16.1 15.1 

PER (adjusted) x 24.5 28.5 27.5 27.3 25.5 24.4 22.1 19.6 17.7 16.1 15.1 

Price/CF x 14.6 15.6 15.4 14.6 13.2 12.4 11.7 10.9 10.3 9.7 9.3 

Payout ratio % 134.0% 245.4% 80.0% 80.0% 80.0% 80.0% 80.0% 80.0% 80.0% 80.0% 80.0% 

DPS c 22.1 34.8 11.8 11.8 12.7 13.2 14.6 16.5 18.3 20.1 21.3 

Yield % 5.5% 8.6% 2.9% 2.9% 3.1% 3.3% 3.6% 4.1% 4.5% 5.0% 5.3% 

NTA per share c 542 492 496 504 518 510 503 496 489 482 485 

Price/NTA x 0.75 0.82 0.82 0.80 0.78 0.79 0.80 0.82 0.83 0.84 0.83 

Net debt $m 1,553 1,103 1,117 1,186 1,354 1,158 959 756 549 339 127 

Net debt/equity % 30.6% 23.1% 23.2% 24.4% 27.5% 23.3% 19.1% 14.8% 10.6% 6.5% 2.4% 

Net debt/debt + equity % 23.4% 18.8% 18.8% 19.6% 21.6% 18.9% 16.0% 12.9% 9.6% 6.1% 2.3% 

Net debt/EV % 19.4% 13.8% 14.0% 14.9% 17.0% 14.5% 12.0% 9.5% 6.9% 4.2% 1.6% 

Net Interest $m (108) (119) (86) (90) (98) (113) (97) (81) (63) (45) (28) 

EBIT / interest x 4.3 3.7 4.8 4.7 4.6 4.2 5.2 6.7 9.1 13.3 22.2 

Return on assets % 5.4% 5.6% 5.2% 5.2% 5.4% 5.9% 6.3% 6.8% 7.3% 7.8% 8.0% 

Return on equity % 5.2% 4.8% 4.9% 4.9% 5.2% 5.3% 5.8% 6.5% 7.1% 7.7% 8.0% 

Return on funds employed % 7.0% 7.5% 7.0% 6.9% 7.2% 7.8% 8.4% 9.2% 10.0% 10.8% 11.4% 

WACC % 8.6% 8.6% 8.6% 8.6% 8.6% 8.6% 8.6% 8.6% 8.6% 8.6% 8.6% 

ROCE - WACC spread % (1.5%) (1.1%) (1.6%) (1.6%) (1.4%) (0.7%) (0.1%) 0.6% 1.4% 2.3% 2.8% 





Fig 13 Meridian Energy cashflow statement ($NZm) 


30/06/10 30/06/11 30/06/12 30/06/13 30/06/14 30/06/15 30/06/16 30/06/17 30/06/18 30/06/19 30/06/20 

Operating activities 

Net Income before tax $m 277 322 327 329 352 367 406 457 508 558 593 

Tax credit/(paid) $m (93) (95) (92) (92) (99) (103) (114) (128) (142) (156) (166) 

Depreciation/goodwill amortisation $m 174 188 185 206 237 256 259 261 264 267 270 

Other $m 83 - - - - - - - - - - 

Gross cashflow $m 441 414 421 443 490 521 551 591 630 669 697 

(Inc) / dec in working cap. $m 10 (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) 

Inc / (dec) in provisions $m - 0 0 0 0 0 0 0 0 0 0 

Operating cashflow $m 452 414 421 443 490 521 551 590 630 669 697 

Investing activities 

Capital expenditure $m (207) (188) (246) (322) (455) (113) (118) (124) (130) (137) (144) 

Acquisitions / Investments $m (263) - - - - - - - - - - 

Asset sales $m 12 750 - - - - - - - - - 

Other $m - 30 - - - - - - - - - 

Investing Cashflow $m (458) 592 (246) (322) (455) (113) (118) (124) (130) (137) (144) 

Financing activities 

Debt drawndown / (repayment) $m 367 (504) 14 69 168 (196) (199) (203) (207) (210) (55) 

Dividends paid $m (353) (556) (188) (190) (203) (212) (234) (263) (293) (322) (341) 

Finance Cashflow - ex debt repayments $m 13 (1,060) (175) (121) (35) (408) (433) (466) (499) (532) (396) 

Inc / (dec) in net cash held $m 7 (54) - - - - - - - - 157 


Fig 14 Meridian Energy balance sheet ($NZm) 


30/06/10 30/06/11 30/06/12 30/06/13 30/06/14 30/06/15 30/06/16 30/06/17 30/06/18 30/06/19 30/06/20 

Current Assets 

Cash and Cash Equivalents $m 54 - - - - - - - - - 157 

Trade and other receivables $m 199 204 205 217 233 252 269 290 312 337 348 

Inventories $m 6 6 6 7 7 8 8 9 9 10 11 

Current tax receivable $m - - - - - - - - - - - 

Other $m 12 12 12 12 12 12 12 12 12 12 12 

Total Current Assets $m 272 222 223 236 252 271 289 311 334 359 527 

Non Current Assets 

Property Plant and Equipment $m 8,207 7,458 7,519 7,635 7,853 7,710 7,569 7,432 7,298 7,168 7,041 

Goodwill and other intangibles $m 50 50 50 50 50 50 50 50 50 50 50 

Equity Accounted Joint Ventures $m 0 0 0 0 0 0 0 0 0 0 0 

Derivative Financial Instruments $m 172 172 172 172 172 172 172 172 172 172 172 

Other $m 14 14 14 14 14 14 14 14 14 14 14 

Total Non Current Assets $m 8,444 7,695 7,755 7,872 8,090 7,946 7,806 7,668 7,535 7,404 7,278 

Total Assets $m 8,716 7,917 7,978 8,107 8,342 8,218 8,095 7,979 7,868 7,764 7,805 

Current Liabilities 

Current Borrowings $m 284 284 284 284 284 284 284 284 284 284 284 

Accounts Payable $m 202 206 207 220 236 255 273 293 316 341 352 

Provisions $m 1 1 1 1 1 1 1 1 1 1 1 

Derivative Financial Instruments and $m 39 39 39 39 39 39 39 39 39 39 39 

current tax payable 

Other $m 32 32 32 32 32 32 32 32 32 32 32 

Total Current Liabilities $m 557 562 563 575 591 610 628 649 672 697 708 

Non Current Liabilities 

Deferred Tax Liability $m 1,560 1,560 1,560 1,560 1,560 1,560 1,560 1,560 1,560 1,560 1,560 

Non Current Borrowings $m 1,323 819 833 902 1,070 873 675 472 265 55 - 

Term Payables $m 53 53 53 53 53 53 53 53 53 53 53 

Derivative Financial Instruments $m 152 152 152 152 152 152 152 152 152 152 152 

Total Non Current Liabilities $m 3,088 2,584 2,598 2,667 2,835 2,638 2,439 2,236 2,030 1,819 1,765 

Net Assets $m 5,071 4,771 4,818 4,865 4,916 4,969 5,028 5,093 5,167 5,247 5,332 

Equity 

Share Capital $m 1,600 1,600 1,600 1,600 1,600 1,600 1,600 1,600 1,600 1,600 1,600 

Reserves $m 3,685 3,685 3,685 3,685 3,685 3,685 3,685 3,685 3,685 3,685 3,685 

Retained Earnings $m (216) (516) (469) (421) (371) (318) (259) (193) (120) (40) 46 

Other $m 2 2 2 2 2 2 2 2 2 2 2 

Total Equity $m 5,071 4,771 4,818 4,865 4,916 4,969 5,028 5,093 5,167 5,247 5,332 





Fig 15 Meridian Energy taxation ($NZm) 


30/06/10 30/06/11 30/06/12 30/06/13 30/06/14 30/06/15 30/06/16 30/06/17 30/06/18 30/06/19 30/06/20 

Pre-Tax Profit $m 277 322 327 329 352 367 406 457 508 558 593 

Add: Goodwill Amortisation $m (14) - - - - - - - - - - 

Operating Surplus before Taxation $m 264 322 327 329 352 367 406 457 508 558 593 

Tax Expense/(Credit) $m (93) (95) (92) (92) (99) (103) (114) (128) (142) (156) (166) 

Effective Taxation Rate % 33.6% 29.5% 28.0% 28.0% 28.0% 28.0% 28.0% 28.0% 28.0% 28.0% 28.0% 





Financial flexibility and generation 

development 

Meridian Energy’s FY10 gearing ratio (net debt/debt + equity) and EBIT interest coverage 

ratio were 23.4% and 4.3x, respectively. We forecast that these ratios will be 18.8% and 3.7x 

in FY11. We assume that $550m of the $750m Tekapo A and B station proceeds will be 

returned to the Crown through a special dividend in FY11. 

These ratios continue to indicate that the company will have strong financial capacity to 

proceed with further generation development and to maintain an average 75% payout ratio. 

We assume that the modelled projects are able to be funded internally and via debt. Note, 

gearing is forecast to peak at 21.6% in FY14. 

As highlighted previously, Meridian has a large pipeline of generation developments, with 

over 350 MW of new hydro generation and over 1,500 MW of wind projects. 

We outline below our forecast capex for the company out to FY13, as per the development 

pipeline identified earlier. Note, maintenance capex declines from the FY10 level as a half-life 

refurbishment programme at Benmore is now complete. 

Fig 16 Capital Expenditure ($NZm) 

FY08A FY09A FY10A FY11E FY12E FY13E 

30/06/08 30/06/09 30/06/10 30/06/11 30/06/12 30/06/13 

Growth capex $m 269 476 207 98 149 220 

Maintenance capex 

Maintenance capex $m 105 112 132 90 97 102 

Total capex $m 374 589 339 188 246 322 

Source: Company disclosures, Macquarie Research, October 2010 




Sensitivities 

We have determined the sensitivity of the equity valuation to changes in key assumptions. 

The results of these changes are outlined below. 

Fig 17 Sensitivities 

5,000 5,500 6,000 6,500 7,000 7,500 8,000 

Capacity factors 

(-/+ 1%) 

6,211 

6,715 

Carbon cost 

($25/t /$0/t) 

Wholesale electricity prices 

(-/+ $10MWh) 

6,470 

6,391 

6,568 

6,549 

Retail electricity prices 

(-/+ 0.5c/kWh) 

6,163 

6,763 

Customer growth 

(+/- 0.1%) 

Usage per customer 

(-/+ 500kWh pa) 

Debt margin 

(+/- 0.5%) 

6,459 

6,439 

6,375 

6,467 

6,487 

6,553 

Market risk premium 

(+/- 0.5%) 

6,112 

6,853 

LWAP 

(+/- 1% point) 

6,370 

6,556 

NZAS base price escalation 

(+/- 1% point) 

6,152 

6,815 

Maintenance capex cost inflation 

(+/- 0.5% point) 

6,326 

6,590 

Greenfield development timing1 

(+/- 1 year) 

6,159 

6,363 





Alternative valuation methodologies 

We have assessed a comparable company equity valuation for the company of $4,942m- 

$6,198m. This is based on the current earnings multiples of listed comparable 

generators/retailers globally. The band is based on the average multiple for selected global 

generators with a bias toward conventional generation ranging to the average multiple for 

selected global renewable generators. We then applied a relatively arbitrary premium to this 

range to account for MER’s renewable generation bias and its pipeline of generation 

development options. 

This valuation provides a cross-check of the equity valuation based on our primary 

methodology, discounted cashflow. This valuation range is below our primary valuation due, 

in part, to the recent de-rating of global renewable energy multiples (absolutely and vis-a-vis 


A sum of the parts valuation may provide another useful cross-check but is heavily dependent 

on the electricity transfer price assumed. 

Fig 18 Comparable company valuation analysis 

Multiple FY11 Enterprise value Net Debt Equity value 

($m) 

EBITDA 

Low High Low High Low High 

Genesis Energy 8.1x 10.1x 265 2,147 2,677 902 1,245 1,775 

Meridian Energy 9.1x 11.1x 628 5,715 6,971 773 4,942 6,198 

Mighty River Power 8.6.x 10.6x 403 3,466 4,272 971 2,495 3,301 

Contact Energy 9.8x 497 4,891 1,281 3,610 

TrustPower 10.6x 292 3,096 733 2,363 

Source: Capital IQ, FactSet, Macquarie Research, October 2010 




Relative disclosure 

We have summarised below MER’s disclosures of key financial and valuation forecast 

variables over the past 12 months. This assessment is set against those of comparable listed 

companies in NZ. 

Fig 19 Meridian Energy relative disclosure 

Genesis 

Energy 

Meridian 

Energy 

Disclosure Level 1 

Mighty River 

Power Contact Energy TrustPower 

Generation 

Production 

By fuel (GWh) √ √ √ √ √ 

By station (GWh) 

√ 

Prices GWAP ($/MWh) √ √ √ √ √ 

Direct costs 

Operating costs 

Fuel ($m) √ √ NA 

Energy ($m) √ √ √ 

Ancillary services (net) ($m) 

Maintenance ($m) √ √ 

Other ($m) 

√ 

Capital expenditure Maintenance ($m) √ √ √ 

Greenfield prospects 

Capex ($m) √ √ √ √ 

Opex ($m) 

Capacity factor (%) √ √ √ √ √ 

Electricity Supply 

Volume by price exposure 

Customer breakdown 

Energy use per customer 

Tariffs 

Other costs 

Fixed price variable volume (GWh) √ √ √ √ √ 

Spot (GWh) √ √ √ √ √ 

CFD - net (GWh) √ √ √ 

Mass market (ICPs) 

SME (ICPs) 

TOU (ICPs) 

Mass market (MWh) 

SME (MWh) 

TOU (MWh) 

Mass market ($/MWh) 

SME ($/MWh) 

TOU ($/MWh) 

Cost to serve ($m) 

√ 

Ancillary services (net) ($m) 

√ 

LWAP ($/MWh) √ √ √ 

Gas Supply 

Customer breakdown 

Energy use per customer 

Mass market (no.) NA NA 

SME (no.) NA NA 

Corporate (no.) NA NA 

Mass market (TJ/cust.) NA NA 

SME fixed (TJ/cust.) NA NA 

SME/Corporate spot (TJ/cust.) NA NA 

Operating costs 

Source: Company disclosures, Macquarie Research, October 2010 

Direct ($m) NA √ NA 

Other ($m) NA √ NA 




Fig 20 EV/EBITDA (Jun-11) 

Fig 21 EV/EBIT (Jun-11) 

20x 

18x 

16x 

14x 

12x 

10x 

8x 

6x 

4x 

2x 

- 

THEOLIA 

EDF Energie Nouvelles 

TrustPower 

INFIGEN 

EDP Renovaveis 

Iberdrola Renovables 

ERG Renew 

Origin 

Contact 

TransAlta Corporation 

AGL 

Scottish and Southern Energy 

NextEra Energy 

Iberdrola 

EDP 

Enel 

International Power 

EDF 

E. ON 

45x 

40x 

35x 

30x 

25x 

20x 

15x 

10x 

5x 

- 

THEOLIA 

INFIGEN 



TrustPower 


ERG Renew 


Contact 

Origin 

EDP 


Iberdrola 

AGL 


EDF 

Enel 


E. ON 

Source: Company disclosures, Macquarie Research, October 2010 Source: Company disclosures, Macquarie Research, October 2010 

Fig 22 Gearing (Net debt / EV) 

Fig 23 Market cap vs EV (NZ$b) 

1x 

1x 

1x 

1x 

1x 

0x 

1x 

1x 

1x 

1x 

1x 

0x 

0x 

0x 

- 

0x 

0x 

0x 

0x 

- 

THEOLIA 

INFIGEN 



ERG Renew 

TrustPower 


EDP 

Enel 



EDF 

Iberdrola 



E. ON 

Contact 

Origin 

AGL 


TrustPower 

ERG Renew 



INFIGEN 

THEOLIA 

AGL 

Origin 

Contact 


E. ON 



Iberdrola 

EDF 


EDP 

Enel 


Fig 24 EBITDA margin (Jun-11) 

1x 

1x 

1x 

1x 

Fig 25 EBIT margin (Jun-11) 

0x 

0x 

0x 

0x 

0x 

0x 

0x 

0x 

0x 

0x 

0x 

0x 

- 

- 



INFIGEN 

TrustPower 


THEOLIA 

ERG Renew 




Iberdrola 

EDP 

EDF 

Enel 

Contact 

Origin 

E. ON 

AGL 




TrustPower 


INFIGEN 

THEOLIA 

ERG Renew 



Iberdrola 


Enel 

EDP 

EDF 

Origin 

Contact 

E. ON 

AGL 





Important disclosures: 

Recommendation definitions 

Macquarie - Australia/New Zealand 

Outperform – return >5% in excess of benchmark return 

Neutral – return within 5% of benchmark return 

Underperform – return >5% below benchmark return 

Macquarie – Asia/Europe 

Outperform – expected return >+10% 

Neutral – expected return from -10% to +10% 

Underperform – expected return +10% 

Neutral – expected return from -10% to +10% 

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Neutral – return within 5% of benchmark return 

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3000 index return 

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AU/NZ Asia RSA USA CA EUR 

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Appendix 1 

Meridian Energy equity valuation – pre Electricity Industry Act 

Macquarie Research’s discounted cashflow-based equity valuation for Meridian Energy is 

$6,469m (enterprise value $7,992m) assuming a nominal WACC of 8.6%, asset beta 0.60 

and TGR 3.0%. 

Meridian Energy DCF equity valuation summary 

Perpetuity growth rate 3.0% 

Perpetuity Value 12,566 

PV (FY10-29) 4,868 

PV of Perpetuity 2,864 

PV FCF available to owners 7,732 

Plus: book value of international assets 260 

Plus: proceeds from sale of Tekapo 0 

Plus: settlement receivable 30 

Less Net Debt (1,553) 

Equity Value 6,469 

Shares Outstanding (m) 1,600 

DCF Equity Value per share 4.04 

Assumptions 

Corporate Tax Rate 28.0% 

Risk free rate 5.50% 

Asset beta 0.6 

Equity beta 0.75 

Market Risk Premium 7.0% 

Target Debt/Venture 20% 

Target Equity/Venture 80% 

Cost of Debt 8.25% 

Tax-adjusted Cost of Debt 5.94% 

Ungeared Cost of Equity 7.37% 

Cost of Equity 9.21% 

Nominal WACC (%) 8.56% 

Source: Company data, Macquarie Research, November 2010 

This valuation is calculated after excluding the impact from the Electricity Industry Act (EIA) 

modeled and summarised through this report. We note the following: 

1. The virtual asset swaps contained in the EIA were assumed to be transacted at fair 

value; 

2. The Tekapo A and B station physical asset swap impacted, inter alia, generation output, 

direct and indirect costs, maintenance capital expenditure and the group LWAP/GWAP 

ratio. 

1 November 23

Valuation Report 2010 - Meridian Energy - Macquarie - The Crown ...

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