Mighty River Power FY2012 Financial Results Presentation

28th August 2012

Financial Results 12 Months ended 30 June 2012

Presented by: Doug Heffernan Chief Executive

William Meek Chief Financial Officer

FINANCIAL RESULTS

Disclaimer > The information in this presentation was prepared by Mighty River Power Limited with due care and attention with every effort made to ensure its accuracy. > Due to Securities Act restrictions the company is not presently in a position to provide forward looking financial information nor to answer questions about its activities or prospects.

This presentation does not constitute financial advice.

Page 2

FINANCIAL RESULTS

Agenda 2012 Highlights Market Dynamics Operational Update Financial Update Business Update Summary Appendix

4 6 12 21 33 39 42

Page 3

FINANCIAL RESULTS

2012 Highlights Financial performance > EBITDAF increased 4% to $461 million in line with increased guidance > NPAT decreased to $68 million, reflecting significant non-cash changes in fair value of financial instruments > Underlying earnings flat at $163 million reflecting increased operational earnings offset by increased depreciation and lower reported equity accounted earnings > Declared total dividends up 9% to $120 million reflecting current dividend policy Operational performance > FPVV electricity sales prices and volumes to customers both increased 5% > Hydro generation down 2% reflecting lower inflows into the Waikato catchment in the last quarter, but still 294GWh above annual average > Flexible portfolio able to take advantage of higher wholesale prices Portfolio developments > Development of 82MW Ngatamariki geothermal plant on track for commissioning in mid-2013 > Energy Source‟s John L Featherstone plant operating since March 2012 with a 99% capacity factor in it‟s first full quarter Capital structure > Extended liquidity headroom to $510 million > BBB+ Standard & Poor‟s credit rating, with Stable outlook Page 4

FINANCIAL RESULTS

2012 Financials 800

700

685 655

$million

600

500 443

461

400

FY2011

362

FY2012 293

300

264

277

233

220

200

162163 127

110120

93

100

68 26

0 Energy Margin

% change $m change

5% $30m

Operating Expenditure

(14%) ($32m)

EBITDAF

Fair Value Adjustments

4% $18m

(263%) ($67m)

NPAT

(47%) ($59m)

Underlying Earnings

Operating Cash Flow

0.3% $0.5m

(5%) ($16m)

Capital Total declared Expenditure dividend

64% $142m

9% $9m Page 5

FINANCIAL RESULTS

2012 Market Dynamics

Page 6

MARKET DYNAMICS

Demand Electricity Consumption

> Consumption broadly flat in the last five years reflecting

45,000 40,000

> fluctuating demand from Tiwai > weak economic conditions > Christchurch earthquake

5,246

4,098

4,947

5,350

5,247

34,138

34,241

34,239

34,075

33,822

2008

2009

2010 Financial year

2011

2012

30,000 GWh

> Excluding Tiwai demand continued to be relatively flat in FY2012 at 33,822GWh > Tiwai decreased consumption by 103GWh over the year mainly in the second half

35,000

25,000 20,000 15,000 10,000 5,000 0

National Consumption

Tiwai Consumption

Page 7

MARKET DYNAMICS

Demand > Residential households account for 33% of total national electricity consumption by volume (GWh) and 87% by Individual Connection Points (ICPs) > Retail churn within ICPs, which are predominately residential, remains high but recently levelled out Monthly Total Consumer Retail Switching (ICPs)

Electricity Consumption by Sector (2011) 5%

60,000

25%

50,000

20%

20% 40,000

15%

30,000

ICP Retail Switching

Jan-12

Jul-11

Jan-11

Jul-10

Jan-10

0% Jul-09

0 Jan-09

5%

Jul-08

10,000 Jul-07

18%

10%

20,000

Jan-08

33%

% Churn

24% Agriculture, forestry and fishing Residential Commerical(including Transport) Basic Metals (Including Tiwai) Industrial Page 8

MARKET DYNAMICS

Supply > Above average inflows into the Waikato Catchment in the first nine months, lower than average in the last quarter > Record low South Island hydrology during the year > Nationally, low cost hydro generation was replaced with higher cost gas and coal production > Hydro generation down 13% to 21,848GWh > Thermal (coal & gas) generation was up 29% to 11,631GWh Taupo Storage 600

500

500

400

400

Jul 12

Jun 12

May 12

Apr 12

Mar 12

Feb 12

Jan 12

Actual

Dec 11

Jul 11

Average

Aug 11

Jun 12

May 12

Apr 12

Mar 12

Feb 12

Jan 12

0

Dec 11

0 Nov 11

100 Oct 11

100 Sep 11

200

Aug 11

200

Nov 11

300

Oct 11

300

Sep 11

GWh

600

Jul 11

GWh

Waikato Inflows

Note: Average for Waikato inflows calculated since 1927 and average for storage since 1999 when Might y River Power began operating the Waikato Hydro system

MARKET DYNAMICS

Wholesale prices > Despite a record dry spell in the South Island wholesale price increases were relatively modest compared to dry spell in 2008 > Since 2008, renewables have displaced thermal capacity, leaving more thermal capacity able to respond to dry conditions > Increased competition between thermal plants, led to higher availability of lower priced hedge contracts than in 2008 by these plants Average Wholesale Price (WKM) 120 103 100 83

$/ MWh

80 60

55

56 48

40 20 0 2008

2009

2010 Financial year

2011

2012 Page 10

MARKET DYNAMICS

North Island – South Island differential Spread (OTA-BEN)

> transmission capacity restrictions > South Island reserve offers

40 20

0 $/MWh

> Wholesale price spread given the record low South Island hydrology in the last nine months of the year > Spread significant in the fourth quarter given

-20 -40 -60 -80 Jun 12

May 12

Apr 12

Mar 12

Feb 12

Jan 12

Dec 11

Nov 11

Oct 11

Sep 11

Aug 11

Average Wholesale Price 250 200 150 100 50

OTA

Jun 12

May 12

Apr 12

Mar 12

Feb 12

Jan 12

Dec 11

Nov 11

Oct 11

Sep 11

Aug 11

0 Jul 11

$/ MWh

Transmission upgrades > Transpower is increasing the northward and southward capacity of the HVDC interisland link > Expansion will mean less reserve market pressures

Jul 11

-100

BEN Page 11

FINANCIAL RESULTS

Operational Update

Page 12

OPERATIONAL UPDATE

Electricity Generation > 1,597MW in operation (1,464MW by equity share), 82MW geothermal station under construction > Diversified and flexible portfolio annual production increased by 3% to 7,068GWh > 61% hydro –peaking capacity with limited storage in Taupo lake; mainly rain fed (not snow fed) > 31% geothermal – high availability, low fuel cost renewable base-load – „premium‟ renewable > 8% gas-fired – can take advantage of wholesale market opportunities and provides dry-year cover Total Generation 8,000 6,833

7,068

7,000 6,129 5,812

6,000 5,292 GWh

5,000 Biomass 4,000

Gas-fired Hydro

3,000

Geothermal 2,000 1,000 0 2008

2009

2010 Financial year

Note: Sold last of biomass operations in July 2010

2011

2012 Page 13

OPERATIONAL UPDATE

Electricity Generation Hydro

5,000 4,500

> Hydro generation down 2% from FY2011 but still 294GWh above annual average

Historical Average from FY2000

4,000 3,500

2,148

GWh

3,000

2,036

> Used Southdownâ€&#x;s flexibility to take advantage of high wholesale prices

H2

> Geothermal base load generation had average availability factor of 95%

2,500

2,000

4,350 3,730

3,651

1,500 1,000

2,220

2,258

FY2011

FY2012

> 2 April sold 10% interest in Nga Awa Purua (30GWh reduction in generation per quarter)

H1

500 0 FY2008

FY2009 FY2010 Geothermal

Gas-fired

1200

2,500 2,193

2,186 1000

2,000

800

1,562 1,500

GWh

GWh

1,303

1,000

600

1,094 281

H2

273

308

H1

FY2011

FY2012

400 505

500

443

200

504

0

0 FY2008

FY2009

FY2010

FY2011

FY2012

FY2008

FY2009

FY2010

Page 14

OPERATIONAL UPDATE

Generation Plant Operations

%

Hydro Availability 100 90 80 70 60 50 40 30 20 10 0

92%

92%

87%

88%

> Increased planned outages in FY2012 as lifecycle work continues on hydro stations namely Ohakuri and Arapuni

85%

> Transformer and gas turbine failures at Southdown in FY2012 > Geothermal availability 99.7% in the last quarter 2008

2009

2010 2011 Financial Year

2012 Gas-fired Availability

Geothermal Availability 96%

91%

93%

95%

2010 Financial Year

2011

2012

%

94%

%

100 90 80 70 60 50 40 30 20 10 0

2008

2009

100 90 80 70 60 50 40 30 20 10 0

95%

2008

97%

2009

88%

89%

2010 Financial Year

2011

84%

2012 Page 15

OPERATIONAL UPDATE

Electricity Sales > Physical sales (FPVV) volumes increased 5% to 5,021GWh, reflecting a strong increase in commercial volumes > Contract to move approx 5,000 of Meridian‟s Christchurch pre-pay customers to GLO-BUG by the end of September > FY2012 debt write-offs $3.6 million (2011: $3.8 million) – represents $9 per customer > Continued success of 3 year fixed plan with more than 84,000 customers on this tariff plan (2011: 68,000) Physical and Financial sales 12,000 10,000 8,000 GWh

1,397 6,000

1,919

2,113

757

539

810

2,022

2,106

1,997

2,245

2,124

2,411

640 2,027

2,012

2,105

2,240

4,000

1,212 Spot Sale CFDs - ASX & Energy Hedge Market

1,755

1,929

2,223

2,387

2,612

2,652

2,609

2008

2009

2010 Financial Year

2011

2012

Sale CFDs - Inter-generator Sale CFDs - End-user

2,000

Business FPVV Residential FPVV

0

Page 16

OPERATIONAL UPDATE

Electricity Sales > Residential volumes fell back slightly to FY10 levels > 14% lift in business sales volumes to 2,412GWh

> Medium business segment experienced the highest growth and the average contract term for new business has grown from 2.0 to 2.7 years in FY2012 Residential volume 2,700

2,612

2,500

Business volume 2,700

2,609

2,500

2,387

2,223

2,412 2,245

2,300 GWh

GWh

2,300

2,652

2,100 1,900

2,124 2,100 1,929

1,900 1,755

1,700

1,700 1,500

1,500 2008

2009

2010 2011 Financial Year

2012

2008

2009

2010 2011 Financial Year

2012

Page 17

OPERATIONAL UPDATE

Contracts for Difference > Only major change, VAS contract increased by 300GWh in January 2012 (buy and sell-side Inter-generator CFD) 2,000

Buy CFD - Inter-generator

1,000 1,395

1,673 1,192

1,098

1,240

Buy CFD - End User 0

GWh

Buy CFD - ASX and Energy Hedge Market -1,000

(2,027)

(2,240)

(2,022)

(2,106)

(1,997)

Sell CFDs - Industrial Users

Sell CFDs - Inter-generator -2,000 (539)

(640)

(810)

(757)

(1212)

Sell CFD - ASX and Energy Hedge Market

-3,000 Net CFD position

-4,000 2008

2009

2010 Financial Year

2011

2012 Page 18

OPERATIONAL UPDATE

Net Position adjusted for volume profile and generation locations > Vertically integrated portfolio largely square through the year, slightly short in the fourth quarter due to elevated South Island prices and slightly reduced hydrology > adjusted short position: 221GWh, unadjusted short position: 34GWh

> VAS increased by 300GWh in January 2012 and exercised 51GWh of swaption in the fourth quarter 4,000

100 90

2,000

474 467 165

1,000 GWh

1,298

731

716

711

499 129

435 181

489 44

502 249

1,165

1,204

1,344

1,318

480

1,091

1,503

460 119

453 119

482 198

1,124

1,178

990

692

0 -1,000

80 70 60 50

(1,762)

(1,453)

(1,605)

(1,569)

(1,671)

(1,339)

(1,373)

(1,746)

$/MWh

3,000

40 30

(960)

-2,000

(1,190)

(1,056)

(1,087)

(1,079)

(1,448)

(1,199)

(1,647)

-3,000

20 10

-4,000

0 Q1 11

Q2 11

Q3 11

Q4 11

Q1 12

Q2 12

Q3 12

Hydro Generation

Gas-fired Generation

Geothermal Generation

Total Buy Contracts

FPVV Sales

Total Sell Contracts

Adjusted Net Position

Whakamaru Average Spot Price

Q4 12

Page 19

FINANCIAL RESULTS

Financial Update

Page 20

FINANCIAL UPDATE

Change in Segment Reporting > “Wholesale” and “Retail” segments have been combined in a new segment called “Energy Markets” > The “Other segment” includes metering, upstream gas and international geothermal developments > The “Unallocated” includes other corporate support services and other elimination adjustments Year ended 30 June $million

2012

2011 (new disclosure)

2011 (old disclosure)

Wholesale

336.5

Retail

133.7

Energy Markets

499.0

470.1

Other Segments

0.7

2.8

(27.1)

Unallocated

(38.2)

(29.9)

-

EBITDAF

461.5

443.1

443.1

Page 21

FINANCIAL UPDATE

Income Statement Year ended 30 June $ million Energy Margin

2012

2011

$m change

% change

684 .6

654 .7

29 .9

4 .6%

41 .3

21 .2

20 .1

94.8%

(264 .4)

(232 .9)

(31 .5)

13 .5%

461 .5

443 .1

18 .4

4 .2%

(158 .4)

(145 .4)

(13 .0)

8 .9%

(92 .8)

(25 .6)

(67 .2)

262 .5%

(4 .0)

(19 .8)

15 .8

(79 .8%)

Equity accounted earnings of interest in jointly controlled entities and associates

(24 .8)

5 .0

(29 .8)

(596.0%)

EBIT

181 .5

257 .2

(75 .7)

(29 .4%)

Net interest expense

(72 .6)

(71 .8)

(0 .8)

1 .1%

Income tax expense

(41 .3)

(58 .4)

17 .1

(29 .3%)

Net profit after tax

67 .7

127 .1

(59 .4)

(46 .7%)

162 .7

162 .2

0 .5

0 .3%

Other income Operating expenses EBITDAF

Depreciation and amortisation Change in fair value of financial instruments Impairments

Underlying earnings after tax

Page 22

FINANCIAL UPDATE

Operating earnings (EBITDAF) > > > >

Generation and Sales changes largely due to higher wholesale prices Fuel cost increased due to higher Southdown generation Contracts decreased due to net short position and higher wholesale prices One-off contribution from the 10% sale of Nga Awa Purua ($8 million) and sale of emission units ($7 million)

800 231.5

700

23.1

22.3

156.2

$ million

600 500

20.1

443.1

31.6

461.5

400

Increase Decrease

300 200 100 0 EBITDAF FY11

Generation

Fuel cost

Contracts

Sales

Other income

Operating Expenses

EBITDAF FY12

Page 23

FINANCIAL UPDATE

Operating Expenses > Maintenance expenses up $16 million > Costs at Southdown of $12 million, mainly relating to transformer and gas turbine failures > Lifecycle work of hydro plants

> Other expenses up $10 million mainly reflecting costs arising from early termination of a long-term contract, higher professional fees and insurance costs > $3.8 million borne on preparation for potential listing 270 10.8

265

264.4

260 255 15.9

$ million

250

1.4

1.8

1.5

245 Increase Decrease

240 235

232.9

230 225 220 215 Operating Expenses FY11

Maintenance expenses

Sales & Marketing

International Geothermal

Employee Expenses

Other

Operating Expenses FY12

Page 24

FINANCIAL UPDATE

EBITDAF to NPAT > Depreciation and amortisation increased by $13 million reflecting increased asset valuations in FY2011 and amortisation of intangible assets > Change in fair value of financial instruments was $118 million, only $13 million in H2 > $93 million relate to Mighty River Power > $25 million relate to associate companies and jointly controlled entities 500

461.5

158.4

450 400

$ million

350 118.5

300 250

4

200

0.9

Increase Decrease

72.6

150 41.3

100

67.7

50 0 EBITDAF FY12

Depreciation & amortisation

Change in fair value of financial instruments

Impairments

Equity Accounted Earnings (excluding fair value adjustments)

Net interest

Income tax

NPAT FY12

Page 25

FINANCIAL UPDATE

Fair value of financial instruments > To manage risk and provide certainty, a significant portion of our debt is hedged so the cost of funds is insensitive to movements in interest rates > Under Accounting Standards financial instruments are required to be valued at the end of each reporting period > Movements in the non-hedge accounted derivatives are recognised in the income statement > Change in fair value of financial instruments was $118 million, only $13 million in H2, relating to Mighty River Power and its related international investment companies

5.0

4.0 30/06/2012

3.0

31/12/2011 2.0

30/06/2011

1.0 0.0 Jun 11 Mar 12 Dec 12 Sep 13 Jun 14 Mar 15 Dec 15 Sep 16 Jun 17 Mar 18 Dec 18 Sep 19 Jun 20 Mar 21 Dec 21 Sep 22 Jun 23 Mar 24 Dec 24 Sep 25 Jun 26

NZD Swap Rates(%)

6.0

Page 26

FINANCIAL UPDATE

Capital Expenditure > Ngatamariki 82MW geothermal development > $287 million spent to date > $203 million of which occurred in FY2012

> $74 million of geothermal capital expenditure relates to GGE (2011: $83 million) $388m

400 350 300

$287m 20

$million

250

$289m 17 13 7

Other new investment* $220m 280

200 150

$362m 9 5

35 7

231

38 6

Wind 274

Hydro Gas-fired Geothermal (including GGE)

225

Reinvestment

119 100 50 33

26

2008

2009

0

* Includes smart meters

66

57

2010 Financial Year

2011

73

2012

Page 27

FINANCIAL UPDATE

Consolidated Cash Flow > Net interest increased $8 million reflecting higher debt levels partly offset by less capitalised interest > Investment outflows include Ngatamariki and further deployment of GGE commitment > Gain on sale from Nga Awa Purua and emission credit sale included as investing cash flow $ million

FY2012

FY2011

$m change

% change

Net cash receipts

423 .4

431 .9

(8 .5)

(2 .0)

Net interest paid

(83 .5)

(76 .0)

(7 .5)

9 .8

Taxes paid

(62 .9)

(63 .0)

0.1

(0.2)

Net operating cash flow

277 .0

292 .8

(15 .8)

(5 .4)

Investing cash flow

(291 .6)

(202 .4)

(89 .2)

44 .1

Financing cash flow

27 .8

(68 .8)

96 .6

(140 .4)

Net increase in cash

13 .2

21 .6

(8 .4)

(38.9)

Page 28

FINANCIAL UPDATE

Funding Profile > > > >

Average debt maturity profile of 5.0 years Over FY2012, our debt was hedged 97% through the swap book $50 million increase in existing facilities in September 2011 $200 million commercial paper programme established February 2012, of which $100 million of notes issued as at 30 June 2012 > $200 million three-year bank facilities raised in March 2012 sufficient to cover repayment of $200 million retail bond which matures in May 2013 Debt Maturities as at 30 June 2012 300 250

$m

200 60 150

300

250 100

200

200 140

50 0

Drawn Facilities Undrawn Facilities

163 120

58 39 30 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026

Financial Year Note: Undrawn facilities excludes commercial paper programme

Page 29

FINANCIAL UPDATE

Balance Sheet > Upwards revaluations of $417 million in FY2011 and $170 million in FY2012 > Increase in current liabilities due to commercial paper programme ($200 million) and retail bond maturing in May 2013 ($200 million) > Increased receivables and payables due to higher wholesale power prices

$ million

FY2012

FY2011

$m change

% change

3,014.2

2,906.5

107.7

3.7%

394.3

271.7

122.6

45.1%

Non-current assets

5,483.1

5,104.9

378.2

7.4%

Total assets

5,877.4

5,376.6

500.8

9.3%

642.1

225.5

416.6

184.7%

Non-current liabilities

2,221.1

2,244.6

(23.5)

(1.0%)

Total liabilities

2,863.2

2,470.0

393.2

15.9%

TOTAL NET ASSETS

3,014.2

2,906.5

107.7

3.7%

SHAREHOLDERS’ EQUITY Total shareholders’ equity ASSETS Current assets

LIABILITIES Current liabilities

Page 30

FINANCIAL UPDATE

Financial Ratios > Standard & Poorâ€&#x;s credit rating: BBB+/Stable/A2 > Rating reaffirmed in April 2012 30 June 2012 Net debt ($m)

1,115.6

30 June 2011 975.8

Equity/total assets (%)

51.3%

54.1%

Net debt/net debt+equity (%)

27.0%

25.1%

Interest (net) cover (times)

6.4x

6.2x

FFO/interest expense (times)

4.1x

4.8x

25.0x

30.9x

FFO/debt (times)

Page 31

FINANCIAL RESULTS

Business Update

Page 32

BUSINESS UPDATE

Health and Safety > The health, safety and well-being of our people is an absolute priority > Total Recordable Injury Frequency rate down 28% due to a focused plan to enhance an existing strong Health and Safety culture > Raising near miss reporting is important as more reports lead to more learnings and less future injuries > Achieved one year Employee Lost Time Injury (LTI) free > Strong participation in StayLive generation safety group which focuses on sharing information and collaboration on key initiatives to lift standards across the industry Near Miss Incident Frequency Rate

Total Recorded Injury Frequency Rate 2.5

2.18

2.34

12.0 9.70

10.0

2.0

8.0 1.5

1.28 0.92

1.0

6.0

4.90

4.65

2009

2010

4.05

4.0

0.5

2.0

0.0

0.0 2009

2010

2011

Financial Year

2012

2011

2012

Financial Year

Page 33

BUSINESS UPDATE

Domestic Development > 82MW Ngatamariki geothermal power station on track for commissioning mid-2013 > Staged commissioning of the four units beginning after the project is connected to the grid late 2012 > Power output from first two units in third quarter FY2013 > Five of the seven wells have now been drilled for the project > Challenges with the drilling of the second and third injection wells utilised a significant portion of the contingency within the estimated $466 million project cost > Prudent to increase budget contingency by $18 million to be used if drilling of an additional well is needed > In the event additional contingency is utilised real LRMC remains less than $80/MWh

Page 34

BUSINESS UPDATE

Domestic Development > Reviewed development pipeline to ensure a focused effort on the most economic opportunities > Progressing geothermal and wind development options to ensure readiness when market conditions support investment economics Geothermal > Te ia a Tutea (Taheke field) – development agreements with land owners signed in November with exploration expected in 2013 Wind > Turitea wind farm achieved final consent in September 2011 – up to 60 turbines and 180MW > Puketoi wind farm achieved consent (subject to appeal) in June 2012 – up to 53 turbines and 310MW > Consents includes transmission line linking the two projects together

Page 35

BUSINESS UPDATE

International Development > Since establishment of the GGE Fund, secured investment opportunities greater than expected with US$225 million of Mighty River Powerâ€&#x;s capital deployed > GGE is currently seeking further capital to advance the development of its projects > Mighty River Power is working with GGE and will consider contributing further capital alongside new investors > Key GGE developments over 2012 and to date include: > Energy Sourceâ€&#x;s John L Featherstone plant (49.9MW) operational in March 2012. For the last quarter run at a capacity factor of 99% and post construction refinancing underway > Completion of two geothermal wells at Tolhuaca, one producing enough high temperature steam to generate 12MW > Hudson Ranch II signed a 15-year power purchase agreement, drilling to start in September > In Germany acquired four concessions in November 2011 and surface testing and planning underway

Page 36

BUSINESS UPDATE

Water > Treaty of Waitangi issues are a matter for the Crown > Variation 6 increased the water volume for abstraction (primarily dairy irrigation) from the Waikato River > long-term average of 4,000GWh still expected

> Waikato Regional Council to consider whether there should be a 5 year review of consents > Requirement for an “effects greater than anticipated� test to be satisfied

Page 37

FINANCIAL RESULTS

Summary

Page 38

SUMMARY

FY2013 to date > Inflows into the South Island reservoirs improved from lows experienced in 2012

> South Island storage remains 28% below historical averages > Solid inflows into the Waikato catchment at 21% above historical averages and 10% above pcp > Current storage at 348GWh, in line with historical averages > Customer growth experienced in the second half of FY2012 has continued

Page 39

SUMMARY

5 Year Summary Net Profit After Tax – 5 year CAGR (-12%)

EBITDAF – 5 year CAGR 11% 500 400

180

461

160

160

127

140

328

305

120

300 $m

$m

443

447

111

100

200

85 68

80 60 40

100

20

0 2008

2009

2010

2011

0

2012

2008

2009

Financial Year Underlying Earnings – 5 year CAGR 5% 250

2012

Total Dividend – 5 year CAGR 21%

212 162

200

163

140

150*

150

$m

$m

136

2011

250

200 150

2010

Financial Year

100

100 50

50

110

120

2011

2012

87 56

80

0

0 2008

2009

2010

2011

2012

Financial Year

2008

2009

2010

Financial Year

1.

Impacted by fair value accounting of our interest rate swaps

2.

Generation assets revalued by over $2 billion over the last five years which has increased depreciation charges

3.

A special dividend of $150 million was also declared in FY2009

Page 40

FINANCIAL RESULTS

Appendix

Page 41

FINANCIAL RESULTS

Operating Information FY2012 vs FY2011 Twelve months ended 30 June 2012

Electricity Sales FPVV sales to customers

Twelve months ended 30 June 2011

VWAP1 ($/MWh)

Volume (GWh)

VWAP1 ($/MWh)

Volume (GWh)

$115.48

5,021

$110.09

4,776

- Residential customers

2,609

2,652

- Commercial customers

2,412

2,124

FPVV purchases from market

5,323

5,089

Spot customer purchases

2,035

2,136

Total NZEM Purchases Electricity Customers (number)

$94.68

7,358

386,000

$56.76

7,226

392,000

Contracts for Difference - Buy CfD

1,708

1,263

- Sell CfD

3,224

2,947

- Net Sell CfD

1,516

1,684

1.

VWAP is volume weighted average energy only price sold to FPVV customers after lines, metering and fees Page 42

FINANCIAL RESULTS

Operating Information FY2012 vs FY2011 Twelve months ended 30 June 2012 VWAP1 ($/MWh)

Volume (GWh)

VWAP1 ($/MWh)

Volume (GWh)

$87.89

4,294

$52.87

4,368

$100.97

589

$119.90

273

- Geothermal (consolidated)3

$82.11

1,946

$47.38

1,956

- Geothermal (equity accounted)4

$81.80

239

$48.96

236

Total

$87.18

7,068

$53.832

6,833

Electricity Generation - Hydro

- Gas

LWAP/GWAP5 Gas Purchases 6

3.

4.

5.

6.

1.09

1.05

$/GJ

PJ

$/GJ

PJ

- Retail purchases

$8.73

1.1

$8.15

1.05

- Generation purchases

$8.18

5.47

$7.97

2.97

Carbon Emissions (‘000 tonnes CO2e)

1.

2.

Twelve months ended 30 June 2011

628

VWAP is volume weighted average energy only price sold to FPVV customers after lines, metering and fees Reflects the Electricity Authority’s decision to reset prices to around $3,200/MWh in the Auckland region. This ruling is currently under appeal Includes share of Nga Awa Purua generation Tuaropaki Power Company (Mokai) equity share Load weighted and generation weighted average price. This ratio gives an indication of electricity purchase costs compared to the sales price of the electricity produced Prices exclude fixed transmission charges

502

Page 43

FINANCIAL RESULTS

Operating Information H2 2012 vs H2 2011 Six months ended 30 June 2012

Electricity Sales FPVV sales to customers

Six months ended 30 June 2011

VWAP1 ($/MWh)

Volume (GWh)

VWAP1 ($/MWh)

Volume (GWh)

$117.45

2,466

$111.74

2,247

- Residential customers

1,202

1,207

- Commercial customers

1,264

1,040

FPVV purchases from market

2,609

2,403

Spot customer purchases

1,040

1,025

Total NZEM Purchases Electricity Customers (number)

$106.06

3,649

386,000

$54.79

3,428

392,000

Contracts for Difference - Buy CfD

1,017

807

- Sell CfD

1,699

1,458

682

651

- Net Sell CfD

1.

2.

VWAP is volume weighted average energy only price sold to FPVV customers after lines, metering and fees CFD for the six months ended 31 December 2011 have been restated to reflect current methodology of including open AXS positions Page 44

FINANCIAL RESULTS

Operating Information H2 2012 vs H2 2011 Six months ended 30 June 2012 VWAP1 ($/MWh)

Volume (GWh)

VWAP1 ($/MWh)

Volume (GWh)

$95.37

2,036

$52.22

2,159

$110.25

281

$168.892

69

- Geothermal (consolidated)3

$89.47

965

$41.84

979

- Geothermal (equity accounted)4

$90.24

122

$44.36

121

Total

$94.74

3,404

$50.90

3,329

Electricity Generation - Hydro

- Gas

LWAP/GWAP5 Gas Purchases 6

3.

4.

5.

6.

1.12

1.08

$/GJ

PJ

$/GJ

PJ

- Retail purchases

$8.72

0.49

$8.46

0.43

- Generation purchases

$8.25

2.63

8.47

0.93

Carbon Emissions (‘000 tonnes CO2e)

1.

2.

Six months ended 30 June 2011

300

217

VWAP is volume weighted average energy only price sold to FPVV customers after lines, metering and fees Reflects the Electricity Authority’s decision to reset prices to around $3,200/MWh in the Auckland region. This ruling is currently under appeal Includes share of Nga Awa Purua generation Tuaropaki Power Company (Mokai) equity share Load weighted and generation weighted average price. This ratio gives an indication of electricity purchase costs compared to the sales price of the electricity produced Prices exclude fixed transmission charges Page 45

FINANCIAL UPDATE

Income Statement – H2 2012 vs H2 2011 Year ended 30 June $ million

H2 2012

H2 2011

327.7

313.9

28.6

11.1

(149.3)

(115.7)

207.0

209.5

(85.2)

(77.7)

- Change in fair value of financial instruments

(7.1)

(19.8)

- Impairments

(1.3)

(16.3)

- Equity accounted earnings of interest in jointly controlled entities and associates

(5.3)

(3.6)

108.1

92.0

- Net interest expense

(35.6)

(38.2)

- Income tax expense

(22.5)

(19.6)

Net profit after tax

50.1

34.2

Underlying Net profit after tax

61.0

72.8

Energy Margin - Other income - Operating expenses EBITDAF - Depreciation and amortisation

EBIT

Page 46

FINANCIAL RESULTS

NPAT to Underlying Earnings FY2012 vs FY2011 $ million NPAT - Change in fair value of financial instruments - Change in fair value of financial instruments of associate companies - Change in fair value of financial instruments of jointly controlled entities - Impairments

- Income tax expense on adjustments - Impact of tax legislative changes Underlying Earnings

FY2012

FY2011

$m change

% change

67.7

127.1

(59.4)

(46.7)

92.8

25.6

67.2

262.5

1.5

1.4

0.1

7.1

24.2

2.0

22.2

1,110.0

4.0

19.8

(15.8)

(79.8)

(27.5)

(12.9)

(14.6)

113.2

-

(0.8)

0.8

(100.0)

162.7

162.2

0.5

0.3

Page 47

FINANCIAL RESULTS

NPAT to Underlying Earnings H2 2012 vs H2 2011 $ million

H2 FY2012

H2 FY2011

50.1

34.2

- Change in fair value of financial instruments

7.1

19.8

- Change in fair value of financial instruments of associate companies

1.9

1.6

- Change in fair value of financial instruments of jointly controlled entities

3.6

11.8

-Impairments

1.3

16.3

(2.8)

(10.1)

-

(0.8)

61.0

72.8

NPAT

- Income tax expense on adjustments - Impact of tax legislative changes Underlying Earnings

Page 48