Contact Energy. Earnings and target price revision. Price catalyst. Action and recommendation

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1 NEW ZEALAND CEN NZ Price (at 06:38, 14 Aug 2012 GMT) Outperform NZ$4.88 Volatility index Low 12-month target NZ$ month TSR % Valuation NZ$ - DCF (WACC 8.1%, beta 0.6, ERP 7.0%, RFR 4.0%) 5.58 GICS sector Utilities Market cap NZ$m 3, day avg turnover NZ$m 2.6 Number shares on issue m Investment fundamentals Year end 30 Jun 2012A 2013E 2014E 2015E Revenue m 2, , , ,591.2 EBIT m Reported profit m Adjusted profit m Gross cashflow m CFPS CFPS growth % PGCFPS x PGCFPS rel x EPS adj EPS adj growth % PER adj x PER rel x Total DPS Total div yield % Franking 1 % ROA % ROE % EV/EBITDA x Net debt/equity % P/BV x NZ imputation credits are only able to be used by shareholders to offset NZ income tax liability. CEN NZ vs NZSE50, & rec history Note: Recommendation timeline - if not a continuous line, then there was no Macquarie coverage at the time or there was an embargo period. Source: FactSet, Macquarie Research, August 2012 (all figures in NZD unless noted) 14 August 2012 Macquarie Securities (NZ) Limited Retail recovering its footing Event (CEN) reported 2H12 EBITDAF and NPAT of $278m and $100m, ahead of Macquarie (consensus) estimates by 11% (6%) and 20% (5%). Final DPS at $0.12 was in line. Impact The positive operating earnings variance for us seems to be in: higher retail electricity contribution (driven by +4% increase in average realisation versus Macq. estimate +2.0% pcp or $13m positive variance); higher spot exposed revenue (higher peak/ccgt spark spread and lower net swaption cover costs of around $11m versus FY11); Higher net ancillary revenues (possibly $20m higher pcp with around half this amount sustainable on an ongoing basis); lower carbon costs on lower unit cost; lower 2H gas generation cost ($3m positive operating variance) possibly due to reshaping of 2012 and 2013 take-or-pay (TOP) volumes; Higher C&I pricing (CEN indicated it continues to re-contract its book close to ASX futures levels (3Q13 now above $90/MWh) although this impact is difficult to isolate; lower non-fuel operating electricity costs ($3m positive variance). The company indicated it expects its gas re-contracting to provide materials earnings improvement in the next few years. We will check with the company what impact 2H12 contract reshaping is likely to have on unit costs/ccgt operating regime going forward. Earnings and target price revision FY13-15 EPS upgrades of 14%, 24% and 33% resp. on higher retail average realisations and lower interest costs. PT conseq. moves from $5.25 to $5.70. Price catalyst 12-month price target: NZ$5.70 based on a DCF methodology. Catalyst: Nov ASM, further SOE retail tariff adjustments, firming ASX futures Action and recommendation The company is comfortable with FY13 consensus (FY13 EBITDAF pre-result $525m). It indicated that firming retail tariffs, the CY13 swaption roll-over ($10m effective net cost pa), lower carbon costs and lower TOP gas risks are expected to offset a net ancillary revenue step-down ($10m due to dry South Island hydro-inflows) and an over-supplied wholesale market. We suspect that the company is conservative here. Please refer to the important disclosures and analyst certification on inside back cover of this document, or on our website

2 Better exposed generation and retail contributions over 2H12 (CEN) reported 2H12 EBITDAF and NPAT of $278m and $100m, ahead of Macquarie (consensus) estimates by 11% (6%) and 20% (5%). Final DPS at $0.12 was in line. The result is pre-fair value adjustments (-$11.5m), Oakey Power gain on sale ($27.9m) and other smaller costs/impairments (combined -$6.6m). The positive operating earnings variance seems to be in: higher retail electricity contribution (driven by +4% increase in average realisation versus Macq. estimate +2.0% pcp or $13m positive variance); higher spot exposed revenue (higher peak/ccgt spark spread and lower net swaption cover costs of around $11m versus FY11 ); Higher C&I pricing (CEN indicated it continues to re-contract its book close to ASX futures levels (3Q13 now above $90/MWh which is well above our current estimate) although this impact is difficult to isolate; Higher net ancillary revenues (possibly $20m higher pcp with around half this amount sustainable on an ongoing basis); Lower carbon costs on lower unit cost; Lower 2H gas generation cost ($3m positive operating variance) possibly due to reshaping of 2012 and 2013 take-or-pay (TOP) volumes; Lower non-fuel operating electricity costs ($3m positive variance). Fig 1 2H12 snapshot (FY June) 1H12A 2H12A 2H12E Consensus 2H12E Operating Revenue $m EBITDAF $m Depreciation $m Amortisation $m EBIT - Recurring $m EBIT $m Net Interest Expense $m Pre-Taxation Profit $m Taxation Expense $m Profit after Taxation $m Minorities $m Reported Profit after taxation $m Tax-affected Non -Recurring Items $m Pre Abnormal Profit after Tax $m Adjusted Earnings 1 $m DPS cps Adjusted for non-recurring items 1H12A 2H12A 2H12E Wholesale electricity revenue $m Retail electricity sales (gross) $m Retail electricity sales (net of energy cost) $m Key Operating Variables Average Wholesale Price Realised - GWAP $/MWh GWAP/TWAP (HAY) x Hedge level (volume basis, inc retail) % 88% 93% 85% Total generation (inc. swaption) GWh Energy cost/gwap x Implied CFD income $m Average retail realisation (c/kwh) Growth pcp % 0.6% 4.0% 2.0% Retail electricity customer growth (average pcp) % -4.5% -0.9% 0.5% Gas purchase and transmission cost $/GJ Take or Pay gas losses $m Retail electricity margin ($77/MWh transfer price; LWAP/TWAP 1.09) % 9.0% na 9.0% Source: Company data, Bloomberg mean consensus data, Macquarie Research, August August

3 FCF yield 2019E 2017E 2015E 2013E 2011A 2009A 2007A 2005A 2003A 2001A Macquarie Private Wealth We think unfavourable hydrology and mass-market margin compression, in particular, hurt CEN in 1H12 resulting in a negative variance versus our forecasts. We saw something of a reversal of both factors in this half. A wet North/dry South hydrology mix and over-supplied wholesale market (close to 6,000 GWh of new, largely must run, generation plant versus demand growth of around 1,300 GWh from ) led to an unfavourable exposed generation position for CEN during 1H12; Lower hydro volumes over 1H (-16%) were replaced with more expensive thermal generation with higher wholesale prices only just covering these costs. Wholesale prices were up markedly in percentage terms (+46% pcp to around $79/MWh) but need to reach $75/MWh just to cover the SRMC of CEN s CCGT fleet and around $90-100/MWh to cover its thermal peakers; This half has seen CEN s GWAP closer to $100/MWh which should see an improved exposed generation position (peak/ccgt spark spreads and lower effective swaption cost see below); The OCF result was a blow-out (+50% variance to Macq) partly due to lower tax paid. Te Mihi broadly on track Progress on Te Mihi appears to remain broadly on track (2013 completion versus mid 2013 target at February). We ll clarify whether there has been any slippage. There were some small changes to the capex guidance which we have incorporated (around $50m of geothermal capex appears to have been deferred from F12 to FY13). We summarise our FCF forecasts below. Fig 2 FCF to increase at twice the inflation rate over the next 5 years 16% 14% forecast 12% 10% 8% 6% 4% 2% 0% Source: Company data, Macquarie Research, August 2012 Retail pricing well ahead of Macq; CEN churn returns to national average A better than forecast retail electricity contribution (driven by +4% increase in average realisation versus Macq. estimate +2.0% pcp or $13m positive variance and normalisation of company churn to national levels for the first time since 2008) was an important indicator for us. We think there are clear signs that price convergence over this calendar year may well be characterised by upward pressure in SOE tariffs as opposed to last year s downward pressure in private sector pricing. To wit, each of the three SOE gentailers have announced energy only price increases ahead of our expectations so far this year. We expect to see the SOEs continue to move retail pricing up to more closely reflect the current estimated energy cost (approximately $77/MWh before shape and location adjustments). 14 August

4 Some gas re-profiling over 2H12; material gains over the next few years The company has indicated that it expects its gas re-contracting to provide materials earnings improvement in the next few years. Its CY13 TOP volumes have fallen from 38PJ to 32 in CY12 with a 1PJ reduction effected in respect of this year. CY14 sees a material increase in TOP volumes from the last disclosure as TOP ROFR gas has been confirmed. We will check with the company what impact this is likely to have on gas costs/ccgt operating regime going forward. The published materials talk of reshaping contract volumes from 2H14 to allow CEN to flexibly match retail sales (i.e. renewables generation portfolio will cover mass market load by at least 1.6x FY12 sales with flexible thermal (gas storage plus future contracted gas position) to cover TOU load). Macq. models an average CCGT CF of 60% (LT average of around 80%) and a $9.50/GJ all in gas cost until CY15 and then $0.70/GJ step down from that year. The company has clarified that it does not intend to shift Otahuhu to an OCGT configuration for at least the next year. It continues to work through consenting, manufacturer and gas supplier negotiations as it seeks to optimise its position. Comfortable with guidance (very comfortable?) The company is comfortable with FY13 consensus (FY13 EBITDAF pre-result $525m) with the firmer retail tariffs, the CY13 swaption roll-over, lower carbon costs and lower TOP gas risks expected to offset a net ancillary revenue step-down ($10m due to dry South Island hydro-inflows) and an over-supplied wholesale market. We suspect that the company is conservative here but given, recent volatility, this is understandable. Note, CEN s estimated 500 GWh swaption cover will expire December We estimate that it has a combined variable/fixed call cost of $110/MWh. Based on current forward pricing of around $90/MWh, the effective net cost of this cover is around $10m pa equivalent to the cost saving we have modelled on a full-year basis (i.e. from January 2012). The effective cost of this cover for FY12 based on the exposed GWAP was $7m ($18m FY11). Our upgrades move us slightly higher than pre-release consensus We have upgraded our FY13-15 EPS forecasts by 14%, 24% and 33% resp. These upgrades reflect higher forecast retail average realisations and lower forecast interest costs predominantly. Our PT moves from $5.25 to $5.70 with about half of this due to a lower discount rate and half due to our operating earnings changes. 14 August

5 (CEN:$4.88) Interim Results 1H/12A 2H/12A 1H/13E 2H/13E Profit & Loss 2012A 2013E 2014E 2015E June y/e Sept/June y/e2 Operating Revenue $m Operating Revenue $m EBITDAF - Recurring $m EBITDAF - Recurring $m Depreciation $m Depreciation $m Amortisation $m Amortisation $m EBIT - Recurring $m EBIT - Recurring $m EBIT $m EBIT $m Net Interest Expense $m Net Interest Expense $m Pre-Taxation Profit $m Pre-Taxation Profit $m Taxation Expense $m Taxation Expense $m Profit after Taxation $m Profit after Taxation $m Minorities $m Minorities $m Reported Profit after taxation $m Reported Profit after taxation $m Tax-affected Non -Recurring Items $m (8) Tax-affected Non -Recurring Items $m Pre Abnormal Profit after Tax $m Pre Abnormal Profit after Tax $m Adjusted Earnings 1 $m Adjusted Earnings 1 $m Adj for non-recurring items Wholesale and retail electricity 1H/12A 2H/12A 1H/13E 2H/13E Wholesale and retail electricity 2012A 2013E 2014E 2015E Wholesale electricity revenue $m Wholesale electricity revenue $m Retail electricity sales (gross) $m Retail electricity sales (gross) $m Retail electricity sales (net of energy cost) $m Retail electricity sales (net of energy cost) $m Key Assumptions Key Assumptions Average Wholesale Price Realised - GWAP ($/M Wh) Average Wholesale Price Realised - GWAP ($/M Wh) CFD year average strike price ($/M Wh) CFD year average strike price ($/M Wh) Hedge level (volume basis, inc retail) (GWh) 88% 93% 83% 83% Hedge level (volume basis, inc retail) (GWh) 91% 83% 83% 83% Total generation (GWh) Total generation (GWh) Energy cost/gwap (x) Energy cost/gwap (x) Gas purchase and transmission cost ($/GJ) Gas purchase and transmission cost ($/GJ) Discounted Cashflow Valuation Profit and Loss Ratios 2012A 2013E 2014E 2015E PER (adj Earnings) x PV FCFs Available to Owners $m 5379 EPS (adj Earnings) c Less Net Debt (inc Associate debt share) $m 1437 EPS (Reported) c Equity Value $m 3942 DPS c Shares Outstanding m 707 Revenue Growth % 20% -11% 4% 4% Equity Value per Share $m 5.58 EBIT Growth % 20% 2% 13% 14% Includes PV Tax Losses $m - EBITDA/Sales % 19% 22% 23% 24% EBIT/Sales % 12% 14% 15% 16% Assumptions Effective tax rate % 26% 28% 27% 26% Risk free rate 4.0% Payout ratio % Asset beta 0.57 EV/EBIT x Post-tax market risk premium 7.0% EV/EBITDA x Target D/V 42% EV/Sales x Nominal WACC (%) 8.1% Balance Sheet Ratios Terminal Year Assumptions ROE % EBITDA (FY20) $m 670 ROA % Perpetuity growth rate % pa 2.5 ROFE % Terminal EV/EBITDA x 9.53 Net Debt $m Capex=Depreciation yes Net Debt/Equity % Net Interest Cover (EBIT) x Price/NTA x NTA per share cps EFPOWA m Cashflow Analysis 2011A 2012A 2013E 2014E Balance Sheet 2012A 2013E 2014E 2015E Pre-taxation Profit $m Depreciation & Amortisation $m Tax (Paid)/Credit $m (23) (35) (73) (76) Cash $m Other $m Receivables $m Gross Cashflow $m Inventories $m Changes in Working Capital $m (11) (33) 11 (2) Investments $m Other $m Property, Plant & Equipment $m Operating Cashflow $m Intangibles $m Acquisitions $m Other Assets $m Capital Expenditure $m Total Assets $m Asset Sales $m Payables $m Other $m Short Term Debt $m Investing Cashflow $m (530) (566) (338) (160) Long Term Debt $m Dividend (ordinary) $m Other Liabilities $m Equity Raised $m Total Liabilities $m Other $m Shareholders' Funds $m Financing Cashflow $m 317 (43) (172) (180) Minority Interests $m Total Shareholders' Equity $m Net Change in Cash (inc FX) $m 165 (168) (118) 60 Total Funds Employed $m Source: Company data, Macquarie Research, August August

6 Important disclosures: Recommendation definitions Macquarie - Australia/New Zealand Outperform return >3% in excess of benchmark return Neutral return within 3% of benchmark return Underperform return >3% below benchmark return Benchmark return is determined by long term nominal GDP growth plus 12 month forward market dividend yield Macquarie Asia/Europe Outperform expected return >+10% Neutral expected return from -10% to +10% Underperform expected return <-10% Macquarie First South - South Africa Outperform expected return >+10% Neutral expected return from -10% to +10% Underperform expected return <-10% Macquarie - Canada Outperform return >5% in excess of benchmark return Neutral return within 5% of benchmark return Underperform return >5% below benchmark return Macquarie - USA Outperform (Buy) return >5% in excess of Russell 3000 index return Neutral (Hold) return within 5% of Russell 3000 index return Underperform (Sell) return >5% below Russell 3000 index return Volatility index definition* This is calculated from the volatility of historical price movements. Very high highest risk Stock should be expected to move up or down % in a year investors should be aware this stock is highly speculative. High stock should be expected to move up or down at least 40 60% in a year investors should be aware this stock could be speculative. Medium stock should be expected to move up or down at least 30 40% in a year. Low medium stock should be expected to move up or down at least 25 30% in a year. Low stock should be expected to move up or down at least 15 25% in a year. * Applicable to Australian/NZ/Canada stocks only Recommendations 12 months Note: Quant recommendations may differ from Fundamental Analyst recommendations Financial definitions All "Adjusted" data items have had the following adjustments made: Added back: goodwill amortisation, provision for catastrophe reserves, IFRS derivatives & hedging, IFRS impairments & IFRS interest expense Excluded: non recurring items, asset revals, property revals, appraisal value uplift, preference dividends & minority interests EPS = adjusted net profit / efpowa* ROA = adjusted ebit / average total assets ROA Banks/Insurance = adjusted net profit /average total assets ROE = adjusted net profit / average shareholders funds Gross cashflow = adjusted net profit + depreciation *equivalent fully paid ordinary weighted average number of shares All Reported numbers for Australian/NZ listed stocks are modelled under IFRS (International Financial Reporting Standards). 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