Valuation Report 2010

Meridian Energy

EQUITY RESEARCH – New Zealand ANALYST FIRST NZ CAPITAL SECURITIES LIMITED IS A NZX FIRM Jason Lindsay +64 4 496 5338 [email protected]

29 October 2010 A valuation perspective

PG 1

TABLE OF CONTENTS TABLE OF CONTENTS ...... 2 EXECUTIVE SUMMARY...... 3 Recent Performance ...... 3 Earnings Outlook ...... 3 Base Case Valuation ...... 3 Key Assumptions...... 3 Sensitivity Analysis...... 3 COMPANY PERFORMANCE ...... 4 Trends ...... 4 Sector Outlook ...... 4 Company Outlook...... 7 EARNINGS MODEL ...... 8 Earnings estimates...... 8 Cash Flow Estimates ...... 10 Balance Sheet ...... 10 ASSUMPTIONS ADOPTED...... 13 Economic Assumptions ...... 13 Sector Assumptions...... 13 Specific Assumptions ...... 14 Capex Assumptions...... 15 DISCOUNTED CASH FLOW VALUATION ...... 16 Cost of capital assumptions...... 16 Summary of DCF valuation...... 17 Cash Flows for forecast horizon ...... 17 Key Assumption Sensitivity...... 18 COMPARISON OF DCF VALUATION WITH ALTERNATIVE VALUATION METHODS ...... 19 Peer Company Analysis ...... 19 Peer Company Analysis Commentary ...... 20 APPENDIX 1...... 21

PG 2

EXECUTIVE SUMMARY Recent Performance Meridian Energy’s underlying profit after tax increased by 29% in FY10 to NZ$251.9mn (from NZ$195mn) primarily as a result of an improved LWAP/GWAP factor, and above average storage and high inflows combined with some significant thermal plant outages resulting in a short period of higher wholesale electricity prices. EBITDAF increased by 25% in FY10 to NZ$641.7mn (from NZ$512.4mn). We estimate the lower LWAP/GWAP (load weighted average price to generated weighted average price) factor in FY10 (1.13x versus 1.24x in FY09) added close to NZ$70mn to EBITDAF (although this was mitigated by a return to more normal levels of constraint rental rebates). The full commissioning of the 143MW West Wind project added a further circa NZ$15m to EBITDAF (and would have been more under more normal wholesale electricity prices). Benefits from the cost out programme were also seen. EBITDAF/MWh increased 10.6% from NZ$41.87 to NZ$46.29. Earnings Outlook A large portion of the forecast EBITDAF growth in FY11 and FY12 is as a result of acquisitions/capex (primarily Mt Millar and Te Uku) in FY10 and FY11. A full year contribution from Mt Millar wind farm is expected in FY11 with first turbine commissioning of Te Uku wind farm expected late calendar year 2010 (partial contribution in FY11 and full contribution in FY12). The new NZAS agreement takes effect from 1 January 2013. We forecast a significant lift in earnings as a result (partially reflected in FY13 and the full impact in FY14). Meridian Energy faces a significant increase in HVDC charges as a result of the Transpower Pole 3 project costing up to NZ$670mn due for completion in 2012 (although they will benefit from a lower location factor). We forecast the construction of Central Wind (which is consented) in FY13 and FY14 with commissioning from FY15. We do not forecast any further developments beyond what has been consented. Base Case Valuation Our DCF valuation is based on forecasting Meridian Energy’s cash flow for a 10 year period. This derives an enterprise valuation of NZ$7,495mn and an equity value of NZ$6,276mn using a WACC of 8.6% and a terminal growth rate of 2.5%. Key Assumptions Our retail price path effectively preserves the current profitability of the retail division. We assume the first leg of carbon pricing (from 1 July 2010) is reflected in FY11 (first half) with the removal of the 50% free allocation on emissions from 31 December 2012 causing a further leg up in tariffs FY13 (back half). Intense retail competition and softer wholesale electricity prices in the short term (meaning retail is currently quite profitable) may result in a delay in processing the forecast tariff increases giving rise to downside risk to our forecasts. After lowering our short term wholesale price path to reflect softer hedge data, our wholesale price forecasts are now in line with Energy Hedge and ASX data through to FY15. MED forecasts are higher than our forecast price path in later years. We assume HVAC and HVDC percentage increases in line with Transpower forecasts and CPI and distribution system growth (1.5%) increases to lines company charges. Our long run generation assumptions are based on the 13 year average per Energy Link with 3% efficiency gains on Manapouri and Benmore following recent capital expenditure. Line losses and LWAP/GWAP are forecast in line with historic levels with an improvement the the LWAP/GWAP factor from FY13 following the commissioning of the upgraded HVDC link (Pole 3). We have attempted to unwind the NZAS estimated cash flows liability with reference to wholesale price path forecasts. Our analysis suggests the tariff is at a 19% discount to the forecast wholesale price path. Sensitivity Analysis Relative to others in the sector Meridian Energy is less sensitive to moves in retail tariffs (as a result of their smaller residential book relative to generation), but more sensitive to moves in HVDC pricing.

PG 3

COMPANY PERFORMANCE Trends Meridian Energy’s underlying profit after tax increased by 29% in FY10 to NZ$251.9mn (from NZ$195mn) primarily as a result of an improved LWAP/GWAP factor, and above average storage and high inflows combined with some significant thermal plant outages resulting in a short period of higher wholesale electricity prices. EBITDAF increased by 25% in FY10 to NZ$641.7mn (from NZ$512.4mn). We estimate the lower LWAP/GWAP (load weighted average price to generated weighted average price) factor in FY10 (1.13x versus 1.24x in FY09) added close to NZ$70mn to EBITDAF (although this was mitigated by a return to more normal levels of constraint rental rebates). The full commissioning of the 143MW West Wind project added a further circa NZ$15m to EBITDAF (and would have been more under more normal wholesale electricity prices). Benefits from the cost out programme were also seen. EBITDAF/MWh increased 10.6% from NZ$41.87 to NZ$46.29. Net borrowings increased by NZ$349.1mn in FY10 to NZ$1553.2mn primarily as a result of the acquisition of the Mt Millar wind farm A$191mn, and capital expenditure on the construction of the Te Uku wind farm (NZ$100mn spent to balance date). NZ$353.5mn of dividends (2009 Final and 2010 Interim) were paid to the Crown. Despite the increase in borrowings, as a result of the revaluation of plant (NZ$1.2bn), Net Debt to Net Debt plus Equity only showed a modest increase to 23.4% (from 21.9%). Perhaps a better measure given the potential for variations in equity (through revaluation of assets) is to look at funds from operations (FFO) over net debt (a measure of the ability to service debt). FFO/Net Debt decreased from 38.9% to 33.6%. A summary of the financial results can be found in Figure 4 on page 9 of this report. Sector Outlook The big wet Following the big South Island dry of 2008 (and apart from a brief period February – April 2010 when North Island lake levels decreased to near low levels) New Zealand’s hydro situation has been characterised by above average inflows and storage levels. This continues to date with storage currently 130% of average for this time of year and 30 day average weekly inflows 105% of average for this time of year (and much higher during September 2010). Overbuild of generation In the period to 2005 there were few new generation projects of any size due to a combination of uncertainty around future gas supply and Resource Management Act issues. Ministry of Economic Development (MED) forecasts in 2005 indicated New Zealand needed on average 120-150MW (roughly 1.4% - 1.7%) of additional generation capacity each year to keep pace with growing demand. In the five years since this date 953MW of new supply has been added versus the 600-750MW that was required. Contact Energy’s New Plymouth plant that in recent years was largely used as a dry year peaker was withdrawn from service. Furthermore as a result of the global financial crisis and resulting recession, demand has declined in the two years to 31 December 2009 by 2.8% (partially impacted by the NZAS outage). This has resulted in a short term surplus of generation which will be compounded by the upcoming completion of Contact Energy’s Stratford Peaker (200MW) and Meridian Energy’s Te Uku wind farm (64MW). With Mighty River Power recently delaying its Ngatamariki geothermal plant and Genesis Energy’s Castle Hill wind project unlikely to be commissioned until at least the middle of the decade we expect a period of little development activity (Contact Energy’s Te Mihi project is largely replacement of existing Wairakei generation). We expect the over build situation to rectify itself over the next 2-3 years, faster if Genesis Energy removes Huntly units from service earlier that we currently forecast (one unit in FY14 and one unit in FY16).

PG 4

The MED forecasts electricity demand to grow at 1.5% per annum, down from the historical growth rate of 1.8%. However given the weighting towards wind projects in the development pipeline, MW capacity installed needs to increase at a faster rate (once overbuild is resolved). Demand has returned to growth in 2010 with the three months to September 2010 up 4.1% on the pcp and up 0.4% on the three month period to 30 September 2007 (pre recession). Short term oversupply of gas compounded by inflexible contracts Compounding the problem is a surplus of cheap short term natural gas and inflexible take or pay contracts that mean generators (in particular Contact Energy) have had to run thermal plant during periods of sub economic wholesale electricity prices. Contact Energy’s gas storage project (and the run down of Maui ROFR gas) should alleviate this problem. All resulting in a depressed wholesale electricity price Apart from a brief period during February – April 2010 the wholesale electricity price has remained at levels well below what is required to justify the long run marginal cost of new generation, with an average wholesale electricity price over the last two years of around NZ$60/MWh. Forward prices (both Energy Hedge and ASX) are also weak, currently around 35% softer than they were a year ago for FY11, and around 15% softer than they were a year ago for FY12. Longer dated prices (FY13- FY15) remain in line with our original price path. Our shorter dated (FY11-FY12) wholesale price forecasts are in line with Energy Hedge and ASX forward prices. A final note on price The hydro situation can change rapidly due to New Zealand’s limited storage. Should New Zealand experience drier conditions we expect hydro generators with storage will re price water reasonably quickly. Intense retail competition As a result of the softer wholesale electricity price gentailers are looking to boost fixed price cover and combined with the need to rebalance load in advance of the electricity industry reforms, this has resulted in the most intense level of retail competition seen since the market began. In Figure 1 below we set out electricity market churn which shows a dramatic increase in churn over the last 24 months.

Figure 1: Churn

60,000

50,000

40,000

30,000 Customers 20,000

10,000

- Apr-01 Apr-02 Apr-03 Apr-04 Apr-05 Apr-06 Apr-07 Apr-08 Apr-09 Apr-10

Monthly 12-month moving average

Source: Electricity Commission

PG 5

With churn comes more expense, however more materially the competitive environment has resulted in a flat line of retail tariffs (ex line charges) from late 2008 until recently (with the exception of TrustPower). The most recent two MED quarterly schedule of domestic electricity prices (refer Figures 2 and 3 below) show some movement on price from Contact Energy and Mighty River Power (trading under Mercury Energy). Although Mighty River Power appears to be happy with its current customer numbers (it actually forecasts a slight market share percentage decline in its Statement of Corporate Intent), Genesis Energy is looking to rebalance into the South Island in preparation for it purchase of Tekapo A & B.

Figure 2: Retail c/kWh

Source: MED (TPW not adjusted for Friends Extra discount which can be up to a further 5% on variable charges)

Figure 3: Retail c/kWh less line charges

Source: MED (TPW adjusted for Friends Extra discount)

PG 6

Retail competition is also being drive by smaller fringe players such as Powershop and Pulse Energy offering tariffs significantly below the major players. We think it would be difficult for Pulse Energy in particular to have all its longer term demand covered given its current tariff pricing (hedge cover in 2013 is around the $90/MWh level). At current wholesale spot prices these smaller players are likely making good money however as the wholesale price recovers we expect significant upward pressure on tariffs from smaller under hedged players. We expect retail competition (particularly in the South Island) to remain intense for the next 12-18 months. Electricity Industry Act Our valuation has been prepared on the basis of ‘business as usual’ and does not include the impact of any change in Meridian Energy’s asset base or resulting long-term strategy as a result of the Electricity Industry Act, which legislates for the government’s decisions from the Ministerial Review on improving electricity market performance. The key impacts on Meridian Energy’s operation from the Electricity Industry Act are:  sale to Genesis Energy of the Tekapo A & B power stations and associated infrastructure – the generation volumes from these two power stations average 1,000GWh per annum  agreement with Mighty River Power and Genesis Energy of a long-term swap of South Island/ North Island generation  purchase by Meridian Energy of the 155MW Whirinaki power station unencumbered from any reserve energy scheme obligations  participation in creating a liquid hedge market with all other generators  a new scarcity pricing regime to be implemented by the Electricity Authority. The Act doesn't specify the actual transaction date or the transaction, but confers the shareholding ministers the power to direct the Boards, such direction to be given in writing before 1 November 2011. Company Outlook A large portion of the forecast EBITDAF growth in FY11 and FY12 is as a result of acquisitions/capex (primarily Mt Millar and Te Uku) in FY10 and FY11. A full year contribution from Mt Millar wind farm is expected in FY11 with first turbine commissioning of Te Uku wind farm expected late calendar year 2010 (partial contribution in FY11 and full contribution in FY12). The new NZAS agreement takes effect from 1 January 2013. We forecast a significant lift in earnings as a result (partially reflected in FY13 and the full impact in FY14). Meridian Energy faces a significant increase in HVDC charges as a result of the Transpower Pole 3 project costing up to NZ$670mn due for completion in 2012 (although they will benefit from a lower location factor). We forecast the construction of Central Wind (which is consented) in FY13 and FY14 with commissioning from FY15. We do not forecast any further developments beyond what has been consented. Due to a lack of public information we do not forecast subsidiary earnings (apart from the Mt Millar wind farm). These include solar investment in California, Macarthur wind farm, Powershop, WhisperGen, Damwatch, and Right House. The subsidiaries listed lost NZ$30.4mn at the EBITDAF level in FY10 (although this includes circa NZ$8mn in costs relating to the Australian and Californian acquisitions). Our discussions with management indicate an expectation that this division (ex Mt Millar) returns to breakeven at the EBITDAF level by FY12. Retail electricity churn remains at record levels and although Mighty River Power have largely completed their rebalancing of customers Genesis Energy are just getting started. We expect competition in the South Island (where two thirds of Meridian Energy's residential customer base is located) to remain intense for the next 12-18 months.

PG 7

Finally Meridian Energy earnings, more than most, are subject to swings in hydrology. Our normal year hydro assumptions result in a net long position of around 2,800GWh (that is generation less fixed price variable volume sales, line losses, retail hedges, and Comalco sales). Also note that Meridian Energy will lose 1,000GWh of annual generation as a result of the upcoming physical asset swap. Since FY98 annual generation from the Waitaki scheme and Manapouri has fluctuated 2,300GWh or 18.5% (from the wettest year to the driest year). Hydrology extremes means Meridian Energy has to run a lower level of hedge cover so is subject to a greater fluctuation in earnings. Currently Meridian Energy pay the lions share (around 80%) of the existing HVDC charge with other South Island generators (Contact Energy and TrustPower) paying the balance. We model the status quo to continue once Pole 3 is commissioned (i.e. the three South Island generators will pay the increased cost on the NZ$670mn upgrade. HVDC pricing has been under review for some years with one option being reconsidered (having previously been ruled out) a move to postage stamp pricing (i.e all generators funding the link based on their national generation share). Meridian (with little North Island generation) would be the obvious benefactor from such a move. We think this is unlikely. Another option being considered is a move to levying charges based on generation volumes rather than generation peaks. Currently the charge is set based on the six highest half hourly load during the year. If the pricing model was changed based on generation volume this would allow Meridian Energy’s hydro stations to be used in much more of a peaking capacity with an associated increase in revenue. This would likely have negative implications for those with North Island peaking plant (generally more expensive thermal) therefore any change may be resisted. EARNINGS MODEL Earnings estimates and relevant ratios In Figure 4 on the following page we set out our earnings forecasts for Meridian Energy. In addition to contribution from new developments (Te Uku) or recently required assets (Mt Millar) short term EBITDAF growth is primarily driven by a recovery in the wholesale price through to FY13. Meridian Energy has a large level of spot wholesale sales and unhedged generation sold into the wholesale electricity market (2,841GWh forecast in FY11) and therefore you would expect a lift in EBITDAF in line with this volume multiplied by the increase in the wholesale electricity price. However relatively speaking the increase in EBITDAF is not as high as Genesis Energy’s (where we forecast a similar level of spot plus wholesale market sales) because of Meridian Energy’s higher LWAP/GWAP factor of 1.13x (compared to Genesis Energy of 0.98x) which means they effectively lose 13% of the increase in the wholesale electricity price. We forecast this LWAP/GWAP factor to reduce to more normal levels of 1.10x post the commissioning of the HVDC Pole 3 in CY12. Medium term EBITDAF growth is driven by an increase in the price received under the NZAS agreement from 1 January 2013 offset by an increase in the HVDC charges as a result of the commissioning of Pole 3. One final note on our earnings estimates. The split of FY09 and FY10 expenses is based on annual report disclosure. Our forecasts are based on disclosure provided at the full year results briefing which splits the results between retail and wholesale. There is clearly some reclassification of expense lines between the two methods of disclosure (for example in FY10 it would seem that some of the "other" costs goes into energy related costs (around $25.5m), and some into transmission and distribution (around NZ$6m) for annual reports purposes). Although the moves in expense lines look a little odd (for example employee costs going from NZ$87mn in FY10 to NZ$142mn in FY11) on a total basis the move in expenses is accurate. We believe the full year result briefing is a better method of disclosure for modelling purposes.

PG 8

Figure 4: Profit and loss statement Year ended 30 June $mn FY09a FY10a FY11F FY12F FY13F FY14F FY15F FY16F FY17F FY18F FY19F FY20F Revenue Energy sales 1,865 2,023 2,139 2,475 2,746 2,929 3,069 3,182 3,291 3,403 3,518 3,637 Energy related services revenue 7 16 5 5 5 5 5 5 6 6 6 6 Other revenue 21 22 30 31 32 33 34 34 35 36 37 38 1,892 2,062 2,174 2,511 2,783 2,967 3,108 3,222 3,331 3,445 3,561 3,681 Expenses Energy related costs (789) (744) (728) (986) (1,140) (1,235) (1,278) (1,323) (1,363) (1,405) (1,449) (1,494) Energy transmission and distribution (373) (426) (455) (523) (582) (618) (653) (683) (708) (737) (782) (829) Employee costs (76) (87) (142) (145) (149) (153) (157) (161) (165) (169) (174) (178) Other operating costs (143) (163) (144) (135) (138) (141) (152) (156) (160) (164) (169) (173) (1,380) (1,420) (1,469) (1,789) (2,009) (2,147) (2,240) (2,322) (2,396) (2,476) (2,573) (2,674) EBITDAF 512 642 706 722 774 820 868 899 935 968 988 1,007 Other Net change in fair value of financial instruments (114) (15) Forex contracts reclassified to profit or loss - (33) Depreciation (150) (174) (210) (220) (222) (235) (248) (251) (254) (257) (260) (263) Amortisation of intangible assets (13) (14) (14) (14) (14) (14) (14) (14) (14) (14) (14) (14) Impairment of PPE (6) (1) Impairment of available for sale investments (3) - Impairment of intangible assets - (17) Gain on sale of PPE 5 0 Equity accounted earnings of joint ventures (2) (2) (283) (256) (224) (234) (236) (248) (262) (265) (268) (271) (274) (277) EBIT 229 386 482 488 538 572 607 635 668 698 714 730 Interest expense (73) (87) (102) (99) (81) (63) (81) (61) (38) (13) (0) - Interest income 5 2 3 3 3 3 3 3 3 3 11 23 Net change in fair value of financial instruments loss (32) (23) (101) (108) (99) (97) (78) (60) (79) (58) (35) (11) 11 23 NPBT 128 277 383 392 460 512 528 577 633 687 725 754 Tax (39) (93) (115) (110) (129) (143) (148) (161) (177) (192) (203) (211) NPAT 89 184 268 282 332 369 380 415 455 495 522 543 Underlying profit after tax 195 252 268 282 332 369 380 415 455 495 522 543

EBITDAF per MWh generated 41.87 46.29 50.94 52.16 55.93 59.24 60.85 63.03 65.56 67.88 69.26 70.61 EBITDAF / interest cover 7.5x 7.5x 7.1x 7.5x 9.9x 13.7x 11.0x 15.5x 26.7x 91.9x (91.8x) (43.3x) FFO interest cover 6.9x 6.4x 6.0x 6.3x 8.3x 11.3x 9.1x 12.7x 21.6x 73.6x (73.0x) (34.2x) FFO / average net debt 38.9% 33.6% 32.4% 38.3% 47.5% 52.0% 61.3% 90.2% 163.5% 649.9% (366.7%) (176.0%) Dividend payout ratio 15.4% 140.3% 63.3% 73.1% 69.4% 71.2% 73.9% 71.8% 71.7% 72.0% 73.0% 73.6% Tax rate (normalised) 30.2% 33.6% 30.0% 28.0% 28.0% 28.0% 28.0% 28.0% 28.0% 28.0% 28.0% 28.0%

EBITDAF per MWh generated (SOCI plan) 46.40 49.60 55.30 EBITDAF / interest cover (SOCI plan) 5.4x 5.3x 5.6x FFO interest cover (SOCI plan) 4.6x 4.5x 4.7x Source: Company data, FNZC estimates

PG 9

Cash Flow Estimates In Figure 5 below we set out our cash flow forecasts for Meridian Energy. Due to the lack of public information we do not forecast capex on subsidiary company’s (with the exception of Mt Millar). This includes solar capex and the recently announced Marcarthur wind farm joint venture with AGL Energy. We forecast only consented projects and assume the circa NZ$500m project Central Wind is constructed in FY13 and FY14 with commissioning in FY15. We assume short to medium term stay in business capex of NZ$50m (real) per annum with mid life refurbishments for Mt Millar, Te Apiti and White Hill wind farms over our forecast period. In our terminal year we forecast stay in business capex to increase in line with annual depreciation expense.

Figure 5: Cash flow Statement Year ended 30 June $mn FY09a FY10a FY11F FY12F FY13F FY14F FY15F FY16F FY17F FY18F FY19F FY20F EBITDAF 706 722 774 820 868 899 935 968 988 1,007 Net Interest (99) (97) (78) (60) (79) (58) (35) (11) 11 23 Tax (115) (110) (129) (143) (148) (161) (177) (192) (203) (211) Increase / (decrease) in working capital (45) 20 6 2 (3) (0) (1) (1) 2 2 Net cash inflow from operating activities 314 452 447 535 574 619 639 680 722 765 798 822

Sale of PPE 20 11 ------Sale of investments 4 1 ------Purchase of PPE (466) (197) (199) (54) (310) (331) (78) (76) (78) (77) (79) (263) Capitalised interest (18) (10) (8) - (9) (28) ------Purchase of subsidiaries - (246) ------Purchase of intangible assets (15) (18) ------Purchase of investments (2) (0) ------Net cash (outflow)/inflow from investing (477) (458) (208) (54) (319) (359) (78) (76) (78) (77) (79) (263)

Proceeds from borrowings 576 564 ------Repayment of borrowings (406) (198) (70) (275) (24) 3 (280) (306) (318) (332) (6) - Dividends paid (30) (353) (169) (206) (230) (263) (281) (298) (327) (356) (381) (399) Net cash (outflow)/inflow from financing 139 13 (239) (482) (255) (259) (561) (604) (644) (688) (388) (399)

Net (decrease)/increase in cash (24) 7 ------(0) 0 332 159

Cash at beginning of year 65 48 54 54 54 54 54 54 54 54 54 386 Change in cash (24) 7 ------(0) 0 332 159 Cash at end of year 48 54 54 54 54 54 54 54 54 54 386 546 Source: Company data, FNZC estimates

Balance Sheet and Relevant Ratios In Figures 6 and 7 on the following pages we set out our balance sheet forecasts and relevant ratios (including comparisons to SOCI forecasts) for Meridian Energy.

PG 10

Figure 6: Balance Sheet Year ended 30 June $mn FY09a FY10a FY11F FY12F FY13F FY14F FY15F FY16F FY17F FY18F FY19F FY20F Current assets Cash 48 54 54 54 54 54 54 54 54 54 386 546 Receivables 188 199 274 316 350 374 391 406 419 434 448 463 Inventories 7 6 8 10 11 12 12 13 13 14 14 15 Finance lease receivables - 1 1 1 1 1 1 1 1 1 1 1 Assets classified as held for sale 11 0 0 0 0 0 0 0 0 0 0 0 Derivative financial instruments 13 11 11 11 11 11 11 11 11 11 11 11 267 272 348 392 428 452 470 485 499 514 861 1,036 Non-current assets Finance lease receivables - 5 5 5 5 5 5 5 5 5 5 5 Equity accounted JV 2 0 0 0 0 0 0 0 0 0 0 0 Available for sale investments 7 6 6 6 6 6 6 6 6 6 6 6 Derivative financial instruments 114 172 172 172 172 172 172 172 172 172 172 172 Intangible assets 44 50 50 50 50 50 50 50 50 50 50 50 Deferred tax asset 0 3 3 3 3 3 3 3 3 3 3 3 PPE 6,743 8,207 8,191 8,011 8,095 8,206 8,022 7,833 7,643 7,450 7,254 7,241 6,910 8,444 8,428 8,248 8,331 8,442 8,259 8,070 7,880 7,686 7,491 7,477

Total assets 7,177 8,716 8,776 8,640 8,759 8,894 8,729 8,555 8,379 8,200 8,352 8,513

Current liabilities Payables and accrual 170 202 233 297 339 365 380 395 408 422 439 457 Provisions 1 1 1 1 1 1 1 1 1 1 1 1 Current tax payables 28 32 32 32 32 32 32 32 32 32 32 32 Current portion of term borrowings 123 284 ------Liabilities classified as held for sale 0 0 0 0 0 0 0 0 0 0 0 0 Derivative financial instruments 34 39 39 39 39 39 39 39 39 39 39 39 357 557 304 368 410 436 451 466 479 493 510 528 Non current liabilities Borrowings 1,129 1,323 1,538 1,262 1,238 1,241 961 656 338 6 - - Term payables - 53 53 53 53 53 53 53 53 53 53 53 Derivative financial instruments 106 152 152 152 152 152 152 152 152 152 152 152 Deferred tax liabilities 1,301 1,560 1,560 1,560 1,560 1,560 1,560 1,560 1,560 1,560 1,560 1,560 2,536 3,088 3,303 3,027 3,003 3,006 2,726 2,421 2,103 1,771 1,765 1,765

Total liabilities 2,893 3,645 3,606 3,395 3,413 3,442 3,177 2,886 2,581 2,264 2,275 2,293

Shareholders' equity 4,284 5,071 5,169 5,245 5,346 5,452 5,552 5,669 5,798 5,936 6,077 6,220 Source: Company data, FNZC estimates

PG 11

Figure 7: Balance Sheet Ratios Year ended 30 June FY09a FY10a FY11F FY12F FY13F FY14F FY15F FY16F FY17F FY18F FY19F FY20F ROCE 2.9% 3.3% 3.2% 3.5% 4.1% 4.5% 4.7% 5.2% 5.8% 6.5% 6.9% 7.0% ROE 4.6% 5.4% 5.2% 5.4% 6.3% 6.8% 6.9% 7.4% 7.9% 8.4% 8.7% 8.8% Net debt / EBITDAF 2.3x 2.4x 2.1x 1.7x 1.5x 1.4x 1.0x 0.7x 0.3x (0.0x) (0.4x) (0.5x) Net debt / (net debt + equity) 21.9% 23.4% 22.3% 18.7% 18.1% 17.9% 14.0% 9.6% 4.7% (0.8%) (6.8%) (9.6%)

ROCE (SOCI plan) 4.7% 5.4% 6.3% ROE (SOCI plan) 3.9% 4.0% 5.8% Net debt / (net debt + equity) (SOCI plan) 25.6% 25.3% 27.9% Source: Company data, FNZC estimates

PG 12

ASSUMPTIONS ADOPTED Economic Assumptions In Figure 8 below we set out our house economic forecasts.

Figure 8: Economic forecasts Year ended 30 June Actual Forecasts 2007 2008 2009 2010 2011F 2012F 2013F 2014F 2015F GDP (Production) (1) 1.3 2.4 -2.3 0.7 2.6 3.5 2.7 2.6 2.7 Consumer Price Inflation (2) 2.0 4.0 1.9 1.8 4.9 2.6 2.5 2.6 2.6 90-Day Bank Bill Rate (3) 7.8 8.7 5.3 2.8 3.4 4.4 5.0 5.0 5.0 10-Year Government Bond Rate (3) 6.0 6.4 5.4 5.8 5.6 5.8 5.8 5.8 5.8 (1) Annual average % change (2) Annual % change (3) Average level for June years Source: FNZC estimates

Sector Assumptions In Figure 9 below we set out forecasts generic to the sector.

Figure 9: Sector forecasts Year ended 30 June FY11F FY12F FY13F FY14F FY15F FY16F FY17F FY18F FY19F FY20F Retail tariff growth 5.8% 3.6% 5.4% 3.4% 3.4% 3.9% 3.8% 3.7% 3.7% 3.6% Wholesale price path $/MWh 58.4 77.8 88.4 94.3 97.1 100.1 102.7 105.3 108.1 110.9 Line charge growth 6.4% 7.4% 7.8% 7.4% 5.9% 5.2% 4.1% 4.9% 5.3% 5.4% HVDC charge growth 8.0% 41.0% 21.0% 0.0% 2.0% -0.5% -1.5% -2.0% 5.5% 5.0% Gas price path ($mn/PJ) 8.5 9.1 9.3 9.7 10.0 10.4 10.8 11.3 11.7 12.3 Coal price path ($mn/PJ) 4.3 4.8 5.4 5.5 5.6 5.8 5.9 6.1 6.2 6.4 Cost of carbon (NZ$/tonne) 23.6 22.8 22.1 22.7 23.3 23.9 24.5 25.2 25.8 26.5 Free allocation carbon 50% 50% 25% Bank margin and fees (bp) 200 200 200 200 200 200 200 200 200 200 Source: FNZC estimates

Retail tariff growth Unlike Mighty River Power, Meridian Energy does not split fixed price variable volume between residential and commercial (SME), therefore we have derived a blended tariff based on FY10 actuals and apply our retail price path to this tariff. We assume the first leg of carbon pricing (from 1 July 2010) is reflected in FY11 (first half) with the removal of the 50% free allocation on emissions from 31 December 2012 causing a further leg up in tariffs FY13 (back half). Intense retail competition and softer wholesale electricity prices in the short term (meaning retail is currently quite profitable) may result in a delay in processing the forecast tariff increases giving rise to downside risk to our forecasts. Our retail price path effectively preserves the current profitability of the retail division. At the LRMC of new generation during FY10 (NZ$80/MWh) Meridian Energy’s retail division was flat at the EBITDAF level and likely negative if an allocation of corporate costs is included. Based on our forecasts Meridian Energy’s retail division continues to earn an EBITDAF return of close to zero (pre allocation of corporate costs). According to MED quarterly pricing schedules at August 2010 Meridian Energy’s net energy tariff (note this is just for residential) is 2-4% below Genesis Energy and Mighty River Power, 12% below Contact Energy, and even higher again for TrustPower. In the sensitivity section later in this report we highlight the valuation upside if Meridian Energy was to increase its tariffs more into line with its competitors. Wholesale price path After lowering our short term wholesale price path to reflect softer hedge data, our wholesale price forecasts are now in line with Energy Hedge and ASX data through to FY15. MED forecasts are higher than our forecast price path in later years. Line and HVDC charge We assume HVAC and HVDC percentage increases in line with Transpower forecasts and CPI and distribution system growth (1.5%) increases to lines company charges.

PG 13

Gas and coal price We adopt MED assumptions (ex carbon) for these price paths. Cost of carbon We assume a 50% free allocation for the 30 months from 1 July 2010 to 31 December 2012 and a carbon price in line with the current CER price path on the European Climate Exchange (capped at NZ$25/tonne to 31 December 2012). Specific Assumptions In Figure 10 below we set out assumptions specific to Meridian Energy.

Figure 10: Specific Assumptions FY11F FY12F FY13F FY14F FY15F FY16F FY17F FY18F FY19F FY20F Connection growth 1% 1% 1% 1% 1% 1% 1% 1% 1% 1% Usage growth 1% 1% 0% 0% 0% 0% 0% 0% 0% 0% Line losses 5% 5% 5% 5% 5% 5% 5% 5% 5% 5% LWAP/GWAP 1.13x 1.13x 1.10x 1.10x 1.10x 1.10x 1.10x 1.10x 1.10x 1.10x Existing Comalco tariff (estimated) $/MWh 60.8 62.4 64.0 Comalco tariff from 2013 (estimated) $/MWh 71.6 76.4 78.7 81.0 83.2 85.3 87.5 89.8 Generation assumptions (GWh) Waitaki 7,867 7,767 7,767 7,767 7,767 7,767 7,767 7,767 7,767 7,767 Manapouri 4,922 4,872 4,872 4,872 4,872 4,872 4,872 4,872 4,872 4,872 White Hill 183 183 183 183 183 183 183 183 183 183 Te Apiti 314 314 314 314 314 314 314 314 314 314 West Wind 495 495 495 495 495 495 495 495 495 495 Te Uku 72 215 215 215 215 215 215 215 215 215 Central wind 420 420 420 420 420 420 Total NZ generation 13,853 13,846 13,846 13,846 14,267 14,267 14,267 14,267 14,267 14,267 Mt Millar generation 184 184 184 184 184 184 184 184 184 184 Sale assumptions (GWh) Retail sales 5,586 5,697 5,754 5,812 5,870 5,929 5,988 6,048 6,108 6,169 Retail hedges 347 347 347 347 347 347 347 347 347 347 Spot price electricity sales 1,835 1,835 1,835 1,835 1,835 1,835 1,835 1,835 1,835 1,835 Retail electricity sales 7,768 7,879 7,936 7,994 8,052 8,111 8,170 8,230 8,290 8,351 Line losses 279 285 288 291 293 296 299 302 305 308 Comalco sales 4,730 4,730 4,871 5,011 5,011 5,011 5,011 5,011 5,011 5,011 CFD's 70 70 70 70 70 70 70 70 70 70 Excess generation sold into wholesale market 1,006 882 682 481 841 779 717 654 590 526 Total sales 13,853 13,846 13,846 13,846 14,267 14,267 14,267 14,267 14,267 14,267 Generation exposed to spot 2,841 2,717 2,517 2,316 2,676 2,614 2,552 2,489 2,425 2,361 Source: FNZC estimates

Line losses Line losses (expressed as a percentage of retail sales excluding spot price retail sales and retail hedges) vary between 4-6% in recent years. We assume 5% in our model. LWAP/GWAP Assumed at 1.13x in line with FY10, reducing to more normal levels of 1.10x following the commissioning of the upgraded HVDC link (Pole 3). Due to its significant base load hydro generation Meridian Energy doesn’t capture the peaks some of its competitors do (Genesis Energy and Mighty River Power in particular). As Meridian Energy introduces more must-run wind into the system it is hard to see Meridian Energy’s LWAP/GWAP factor improving much below 1.10x.

PG 14

Comalco tariff Based on NZAS financial statements we have assumed a NZAS (Comalco) tariff of NZ$58/MWh in FY10. The current contract expires on 31 December 2012. A new agreement based on 572MW of continuous consumption for a period of up to 18 years applies from 1 January 2013. The new agreement is a pricing agreement rather than a supply agreement. It is unclear if Meridian Energy will book the Comalco contract through revenue and expenses from 1 January 2013. We have assumed so, however the method of recognition should make little difference to EBITDAF. We have attempted to unwind the estimated cash flows liability (NZ$602mn at 30 June 2010) with reference to wholesale price path forecasts. Our analysis suggests the tariff is at a 19% discount to the forecast wholesale price path (around a 12% increase on the forecast existing tariff in 2012). Generation Our long run generation assumptions are based on the 13 year average per Energy Link with 3% efficiency gains on Manapouri and Benmore following recent capital expenditure. Mt Millar Meridian Energy recently purchased the 70MW Mt Millar wind farm in South Australia for A$191m. Mt Millar is fully operational and has a power purchase agreement (PPA) that runs through to the end of 2012. We estimate a tariff in line with comparable PPA’s entered into at the time. The forward curve for electricity in South Australia in 2012 is A$69.40 with the current spot market for RECs A$34.50. We have applied a 10% discount to the combined price. Capex Assumptions In Figure 11 below we set out our capex assumptions.

Figure 11: Capex assumptions FY11F FY12F FY13F FY14F FY15F FY16F FY17F FY18F FY19F FY20F Stay in business capex (52) (54) (55) (57) (58) (60) (61) (63) (64) (66) Stay in business terminal year (169) Mid life refurbishment Te Apiti (20) (20) Mid life refurbishment - Mt Millar (16) (16) Mid life refurbishment - White Hill (14) (14) Mid life refurbishment - all wind farms (28) (52) (54) (55) (77) (78) (76) (78) (77) (79) (263) Growth capex (147) (255) (255) Total Capex (199) (54) (310) (331) (78) (76) (78) (77) (79) (263) Source: Company data, FNZC estimates

Due to the lack of public information we do not forecast capex on subsidiary company’s (with the exception of Mt Millar). This includes solar capex and the recently announced Marcarthur wind farm joint venture with AGL Energy. We forecast only consented projects and assume the circa NZ$500m project Central Wind is constructed in FY13 and FY14 with commissioning in FY15. We assume short to medium term stay in business capex of NZ$50m (real) per annum with mid life refurbishments for Mt Millar, Te Apiti and White Hill wind farms over our forecast period. In our terminal year we forecast stay in business capex to increase in line with annual depreciation expense.

PG 15

DISCOUNTED CASH FLOW VALUATION Cost of capital assumptions Estimates of future unlevered cash flows are discounted by estimated Weighted Cost of Capital (WACC). WACC represents the assessed returns required by provided by providers of debt and equity capital weighted by their respective contributions of capital. Current gearing is used unless this is deemed to be materially different to target or optimal gearing. WACC is derived using the following formula:

Re * (1-L) + Rd *(1-Tc) * L where:

Re = Cost of equity derived by using the simplified Brennan - Lally version of the Capital Asset Pricing Model

= Rf * (1- Ti) + B* TAMRP

L = Leverage employed (ie the proportion of debt to debt plus equity)

Rd = Cost of debt

Tc = Corporate tax rate = 28%

Ti = Individual investor tax rate = 28%

Rf = Sustainable long term bond = 5.8% B = Estimated equity beta TAMRP = Tax adjusted market risk premium = 7.25%

Notes:  The methodology used above is consistent with that being adopted by the Commerce Commission in assessing returns on infrastructure and utilities. The only modification relates to estimation of Rf.  We use 5.8% as a suitable proxy for the risk free rate as we take the view that current interest rates are cyclical and will normalise when international market conditions normalize. Our valuation sensitivity analysis should capture a range in WACC which should accommodate variation in Rf.  The tax adjusted MRP converts to a MRP used internationally by using the formula MRP = TAMRP - Rf* Ti (ie ~5.5%)  Equity beta is estimated by de-leveraging the equity betas of comparative companies (local and overseas) to calculate an average asset beta for the compcos. The average asset beta is then converted to an equity beta using the firm’s leverage.

PG 16

Summary of DCF valuation (1) Our DCF valuation is based on forecasting Meridian Energy’s cash flow for a 10 year period. This derives an enterprise valuation of NZ$7,495mn and an equity value of NZ$6,276mn using a WACC of 8.6% and a terminal growth rate of 2.5%. Cash Flows for forecast horizon In Figure 12 below we set out cash flows for our 10 year forecast horizon. We value the Meridian energy subsidiaries (which returned negative NZ$30.4m EBITDAF in FY10) at book value and assume the subsidiaries are EBITDAF neutral by FY12. Should Meridian Energy be able to sell any of its subsidiary company’s (WhisperGen is probably the most likely) for greater than book value there is upside risk to our valuation.

Figure 12: Summary of DCF valuation FY11F FY12F FY13F FY14F FY15F FY16F FY17F FY18F FY19F FY20F Assumptions Implied asset beta 0.56 Measured equity beta 0.73 FY10 debt / debt plus equity ratio 23.4% FY10 equity / debt plus equity ratio 76.6% Risk free rate 5.8% Borrowing premium 2.0% Market risk premium 7.3% Tax rate 28.0% After tax borrowing cost 5.6% Cost of equity 9.5% WACC 8.6% Terminal growth rate 2.5% Free cash flows EBITDA 706 722 774 820 868 899 935 968 988 1,007 Less: Depreciation (210) (220) (222) (235) (248) (251) (254) (257) (260) (263) EBIT 496 502 552 586 620 648 681 711 728 744 Less: Notional Tax Charge (149) (141) (155) (164) (174) (182) (191) (199) (204) (208) NOPAT 347 362 398 422 447 467 491 512 524 536 Less: Capex (199) (54) (310) (331) (78) (76) (78) (77) (79) (263) Plus: Depreciation 210 220 222 235 248 251 254 257 260 263 Less: Net Working Capital (45) 20 6 2 (3) (0) (1) (1) 2 2 FCFF 313 547 316 326 613 642 666 692 708 538 Valuation Discount period 0.2 1.2 2.2 3.2 4.2 5.2 6.2 7.2 8.2 9.2 Discount factor 0.984 0.907 0.835 0.769 0.708 0.652 0.601 0.553 0.510 0.469 FCFF 313 547 316 326 613 642 666 692 708 538 Terminal Value 8,364 313 547 316 326 613 642 666 692 708 8,902 Discounted CF 308 496 264 251 435 419 400 383 361 4,179 Enterprise value 7,495 Less Net Debt (1,490) Add subs at book value (add back debt accounted for above) 270 Equity Value 6,276 Source: FNZC estimates

(1) DCF Valuation - Important Note and Risk Warning Your attention is drawn to the fact that the above DCF valuation and projections of the future performance of Meridian Energy reflect various assumptions by the author of this report, which may or may not prove correct. Some assumptions inevitably will not materialise and unanticipated events, unknown risks, uncertainties and other circumstances will likely occur. Therefore, the actual results achieved during the period of the projections shown will vary from those projected, the valuation will also vary from that presented, and such variations may be material. Such factors include, amongst other things, the following: general economic and business conditions; competition; regulatory or administrative changes affecting the business; the timing and amount of the company's capital expenses; general sector industry trends and pricing; unexpected operations difficulties and other factors, many of which will be beyond the control of Meridian Energy. First NZ Capital Securities Limited makes no representation or warranty, express or implied, as to the accuracy or completeness of the DCF valuation or the information or assumptions on which such valuation is based or derived from, and nothing in this report shall be deemed to constitute such a representation or warranty. Recipients of this report must carry out their own analysis and are cautioned not to place undue reliance on such forward-looking information.

PG 17

SENSITIVITY ANALYSIS Key Assumption Sensitivity We set out below the sensitivity of our valuation to changes in our key assumptions. Whilst we recognise there is a strong correlation between some of the assumptions in this analysis (for example the impact of the wholesale price and line charges on retail tariffs), this exercise considers each sensitivity in isolation.

Figure 13: Meridian sensitivity analysis Sensitivity to Valuation Variables Change in base value ($mn) Change in base value (%)

DCF variables + 0.5% change in WACC (currently 8.6%) +636 10.1% - 0.5% change in WACC (currently 8.6%) -540 8.6%

Sensitivity to Key Assumptions Retail tariff growth (residential only - assumes SME comparable) ± 5% change ± 200 3.2%

Wholesale price path ± 5% change ± 251 4.0%

HVDC, HVAC, and line charge growth ± 5% change ± 331 5.3%

Line losses (currently 5%) ± 1 percentage point change ± 61 1.0%

LWAP/GWAP factor (currently 1.13x, 1.10x from FY13) ± 1 point change ± 119 1.9% Source: FNZC estimates

PG 18

COMPARISON OF DCF VALUATION WITH ALTERNATIVE VALUATION METHODS Peer Company Analysis

Figure 14: Compcos Yr Company Ticker End PE (x) EV/EBITDA (x) EPS CAGR NIBD/EBITDA FY10a - FY11F FY12F FY13F FY11F FY12F FY13F FY13F FY11F Europe Centrica CNA LN Dec 12.1 10.8 10.4 6.3 5.8 5.6 13.6% 1.0 EOAN E.ON GR Dec 9.3 8.8 8.7 5.7 5.4 5.5 -2.8% 2.4 EDF Energies Nouvelles EEN FP Dec 17.9 14.1 10.6 8.8 6.9 5.8 31.4% 7.5 EDF SA EDF PZ Dec 13.1 11.6 10.2 5.3 5.0 4.7 12.7% 2.4 EDP Renovaveis EDPR PL Dec 23.8 18.6 13.6 6.6 5.6 4.6 34.3% 5.1 Endesa ELE SM Dec 9.6 8.9 9.1 5.5 5.4 5.4 -12.5% 1.8 Enel S.p.A. ENEL IM Dec 8.7 8.1 8.3 5.3 5.1 5.0 -5.6% 2.9 Energias de Portugal EDP PL Dec 9.2 8.0 7.8 6.2 5.7 5.6 5.6% 4.3 ERG Renew EGR IM Dec 44.0 12.6 5.2 4.6 4.1 3.8 -193.2% 6.7 Gas Natural GAS SM Dec 7.6 6.9 6.7 6.7 6.3 6.1 1.1% 3.9 Iberdrola IBE SM Dec 11.0 10.1 10.1 7.6 7.1 6.8 2.4% 3.8 International Power IPR LN Dec 14.3 13.2 11.7 9.0 9.2 8.4 2.2% 3.5 Scottish & Southern Energy SSE LN Mar 10.5 9.7 9.1 8.6 7.9 7.3 4.4% 3.5 Theolia TEO FP Dec na 18.3 na 13.3 10.2 43.8 -17.0% 7.9 Mean 14.7 11.4 9.3 7.1 6.4 8.4 -8.8% 4.0

Americas Boralex BLX CN Dec 16.8 16.8 12.5 4.8 5.3 5.1 17.3% 3.6 Consolidated Edison ED US Dec 14.0 13.5 12.9 7.8 7.2 6.1 7.4% 4.0 DTE Energy Company DTE US Dec 12.7 12.2 11.7 6.3 6.0 5.9 6.9% 3.2 Entergy CP ETR US Dec 11.2 11.8 11.6 7.0 7.1 7.2 -0.2% 3.8 Exelon EXC US Dec 10.9 14.7 16.2 6.3 7.6 7.4 -12.7% 2.0 NRG Energy NRG US Dec 16.7 19.5 41.3 5.7 5.7 6.7 -47.6% 3.1 Ormat ORA US Dec 30.0 21.3 20.8 10.7 8.8 7.6 -1.6% 3.8 PG & E Corp. PCG US Dec 12.8 12.1 11.5 6.1 5.8 5.3 8.7% 3.0 Pinnacle West Capital PNW US Dec 13.9 12.6 11.3 6.8 6.3 5.5 18.1% 3.7 Public Service Enterprise PEG US Dec 11.2 12.0 11.3 6.5 6.6 6.5 -1.5% 2.5 RRI Energy RRI US Dec na na na 9.9 9.9 10.9 -34.1% 5.1 Sempra Energy SRE US Dec 12.2 12.0 10.2 7.9 7.3 6.9 5.3% 4.0 Transalta TA CN Dec 17.6 16.4 13.7 8.2 8.0 8.2 20.9% 4.2 Mean 15.0 14.6 15.4 7.2 7.1 6.9 -1.0% 3.5

Australia and NZ AGL AGK AU Jun 15.6 16.5 16.1 9.3 9.7 9.4 2.3% 0.6 Contact CEN NZ Jun 21.0 16.0 14.0 9.6 8.7 8.7 17.9% 3.0 Infigen IFN AU Jun na na na 8.8 8.0 7.0 -173.9% 9.5 Origin ORG AU Jun 21.4 19.3 18.2 10.1 9.4 9.6 9.2% 1.9 Trustpower TPW NZ Mar 18.9 16.9 15.2 10.8 9.9 9.1 9.8% 2.6 Mean 19.2 17.2 15.9 9.7 9.1 8.8 -26.9% 3.5

GLOBAL Median 13.1 12.6 11.5 6.9 7.0 6.6 3.4% 3.6

Mean 15.4 13.4 12.8 7.6 7.1 7.9 -8.5% 3.8

Meridian Energy 23.4 22.2 18.9 11.0 10.6 9.6 9.6% 2.1 Genesis Energy 14.1 11.6 11.1 7.2 6.4 6.1 22.3% 1.5 Genesis Energy (ex Kupe) 17.0 14.3 13.2 8.4 7.2 6.7 2.9% 1.8 Mighty River Power 26.5 21.0 18.2 11.6 10.3 9.3 14.0% 2.2 Source: IBES, Bloomberg, Iress, Credit Suisse & FNZC estimates

Genesis Energy ex Kupe assumes debt attributable to the Kupe project is the same percentage as debt to debt plus equity for the entire entity.

PG 19

Peer Company Analysis Commentary In Figure 14 on the previous page we set out peer group multiples. Meridian Energy’s EV/EBITDA multiple is significantly higher than the sector average although steadily declines as profitability increases. This is due to the 100% renewable, and primarily hydro nature of the company’s generation assets and the virtually free short run marginal cost of generation. A more suitable listed comparison would be to TPW, with Meridian Energy (at 9.6x in FY13) comparable to TrustPower at 9.1x in FY13. Again Meridian Energy’s primarily hydro nature of the generation assets (versus TrustPower that has more wind which depreciates faster in its portfolio) is likely to explain the slight premium. On a PE basis Meridian Energy attracts a premium for the same reason as its listed New Zealand peers (Contact Energy and TrustPower) do when looking at PE ratios. A significant percentage of the accounting depreciation charge likely relates to revaluation of assets (for example in Contact Energy’s case around one third of the accounting depreciation charge relates to revaluation of assets and is therefore not “real”). If we were to assume Meridian Energy’s depreciation charge includes a similar percentage relating to revaluations then the PE ratio in FY13 would decrease to 15.9x (from 18.9x). The revaluation of assets has come about from the significant increase in the wholesale price path since the start of the decade. In Australia where the electricity price path hasn’t risen as much revaluations have been more moderate and depreciation relating to revaluations is less of an issue (plus the listed players tend to operate newer kit). For this reason when looking at New Zealand gentailers we prefer to look at EV/EBITDA as a more appropriate comparison to offshore peers. As a final cross check of the reasonableness of our valuation we look at the terminal year multiple. The implied EV/EBITDA of Meridian Energy’s terminal value is 8.3x which compares to Mighty River Power at 8.6x (due to a slightly lower WACC), and Genesis Energy at 7.1x (lower margin retail larger part of business, and primarily thermal generation fleet).

PG 20

APPENDIX 1 In Figure 15 below we set out the profitability of the industry as a whole. As gentailers adjusted prices in anticipation of the run down of Maui gas, industry profitability (measured on an EBITDAF/MWh basis) sharply increased from 2003. From 2007 industry profitability stalled as the increased costs of gas again began to be incurred (the Pohokura gas field was commissioned in FY07). EBITDAF growth has returned in 2009 and 2010 although this is more to do with lower generation as a result of the recession rather than increased EBITDAF. 2009 saw the full year benefit of retail tariff increases from 2008 (Figures 2 and 3 earlier in this report) show that until very recently residential tariffs have held flat). Increases in the price of fuel began to moderate from 2010 although we expect the introduction of the emissions trading scheme, retail competition and a lower wholesale electricity price will contain industry profitability growth in FY11 and FY12.

Figure 15: Industry Profitability EBITDAF/ EBITDAF (NZ$mn) GWh (NZ generation only) MWh CEN TPW Mer. MRP Gen. Total CEN TPW Mer. MRP Gen. Total (NZ$) 2010 427 274 642 328 249 1919 9,691 2,017 13,862 5,812 7,576 38,958 49.26 2009 445 261 512 447 202 1869 9,948 2,126 12,237 6,129 8,046 38,486 48.55 2008 567 208 371 305 344 1795 11,035 2,018 11,908 5,954 9,126 40,041 44.83 2007 544 196 476 315 183 1716 11,020 1,941 12,678 5,804 7,992 39,435 43.50 2006 557 186 448 304 221 1716 11,534 1,791 11,256 6,010 8,183 38,774 44.26 2005 491 173 518 298 178 1659 10,627 2,071 13,364 5,586 7,615 39,263 42.26 2004 453 140 418 256 185 1451 10,143 1,738 13,108 5,355 7,131 37,475 38.72 2003 359 112 299 175 160 1104 10,049 1,672 12,691 4,952 6,368 35,732 30.91 2002 293 38 231 140 115 818 8,523 1,522 11,112 3,494 6,948 31,599 25.90 2001 341 66 263 156 127 953 8,660 1,613 12,405 4,006 5,748 32,432 29.40 2000 247 69 212 128 114 770 8,450 1,498 11,974 3,777 5,379 31,078 24.78 Source: Company data (note Mighty River Power generation includes 25% of the Mokai geothermal field)

In Figures 16-21 on the following page we set out time series of company profitability measured as EBITDAF/MWh, and efficiency of capital structure. The ratios (that are not self explanatory) are defined as follows.  FFO Interest Cover. Group EBITDAF less net interest less tax paid plus net interest (effectively group EBITDAF less tax paid) divided by net interest.  FFO/Average Net Debt. Group EBITDAF less net interest less tax paid divided by average net debt. In Figures 22-27 we set out time series of company return on capital employed, and returns on equity. The ratios are defined as follows.  ROCE/ROE. Underlying earnings divided by average equity plus average deferred tax plus average debt [ROE = divided by average equity].  ROCE adjusted/ROE adjusted. Underlying earnings divided by average adjusted equity plus average debt [ROE adjusted = divided by average adjusted equity]. For the purposes of calculating adjusted equity we have attempted to strip out the impact of asset revaluations and changes under NZIFRS (primarily derivative financial instruments and deferred tax liabilities). This should largely remove the impact of different revaluation cycles and methodology (but assumes the relative valuations were fair at the start of our time series). This is not an exact measure as the accounting depreciation charge generally increases with a positive asset revaluation (offset somewhat by an extension of the assessment of useful life). Underlying earnings would likely be significantly higher was it not for this increased depreciation. To get a completely accurate picture we would require a split of the increased accounting depreciation charge between capex and revaluations for each of the five generator/retailers. An alternative measure would be to measure returns adding back depreciation expense (underlying profit plus tax expense) however with tax expense impacted by NZIFRS adjustments not included in underlying profit this also is not completely accurate.  In Figures 26 and 27 we attempt to strip out the impact of depreciation (and tax) showing EBITDAF less net interest expense divided by adjusted capital employed (ROCE adjusted) and divided by adjusted equity (ROE adjusted).

PG 21

Figure 16: EBITDAF per MWh produced (NZ$) Figure 17: FFO interest cover (times)