Delivering new renewables while supporting security of sup
Contact Energy Limited Level 2 Harbour City Tower, 29 Brandon Street, Wellington 6011 | PO Box 10742, Wellington 6143
P: +64 4 499 4001 | W: contactenergy.co.nz
17 February 2025
Delivering new renewables while supporting
security of supply
Six months ended
31 December 2024
1H25
Six months ended
31 December 2023
1H24
Reported
Against reported
EBITDAF
i
$404m ↑ 12% from $362m
Profit $142m ↓ 7% from $153m
Profit per share 17.9 c ↓ 8% from 19.5 c
Operating free cash flow
ii
$138m ↓ 21% from $174m
Stay-in-business capital expenditure (cash) $65m ↓ 24% from $85m
Growth capital expenditure (cash) $179m ↓ 16% from $212m
Key strategic highlights
• Entered Scheme of Arrangement for the proposed acquisition of Manawa Energy.
• New long-term agreement to supply electricity to Fonterra, supporting electrification.
• Final commissioning activities completed on 174MW Tauhara geothermal station.
• Te Huka 3 geothermal station online December 2024. Final commissioning underway.
• Construction started on 100MW Glenbrook battery and 168MWp Kōwhai Park solar farm.
• Confirmed investment in Wairakei extension and Te Mihi Stage 2 geothermal projects.
• Supported the market in winter 2024 by securing Methanex gas and running TCC.
Financial performance
Contact Energy has reported net profit of $142m in 1H25, down 7 per cent ($11m) on the prior year,
with market making and fair value movements in unhedged financial electricity contracts ($21m)
impacting the current period.
iii
Operating earnings (EBITDAF) increased by $42m to $404m, up 12 per
cent.
The improved operating result was driven by increased geothermal generation with Tauhara online,
improved channel pricing from the commencement of long-term contracts and elevated Contracts for
Difference (CFDs) in support of short-term supply conditions. This was partially offset by higher gas
and acquired generation costs, losses on sale of excess gas and one-off costs of $10m associated
with the proposed acquisition of Manawa.
Extreme hydro volatility characterised operating conditions throughout the period, with flow-on
impacts to wholesale pricing as demand response calls and the cost of thermal generation reflected
fuel scarcity. Contact supported the market by facilitating access to ~3.5PJ of gas from Methanex and
increased generation at the Taranaki Combined Cycle (TCC) power station, while also delivering new
geothermal generation into the market.
“The result has been a demonstration of the agility of Contact and the market to respond to
challenging market conditions when unable to rely on the cheap and plentiful natural gas of the past.”
Contact Energy Ltd
2
“Contact’s renewable generation profile has now expanded, with its two new geothermal plants online
and already contributing generation in the first half,” says Chief Executive Mike Fuge. “We expect to
deliver EBITDAF of $790m in FY25 (previously $770m) excluding the costs associated with the
proposed acquisition of Manawa.”
Operating free cash flow of $138m was down 21% on the prior year with the improved operating
result offset by relatively higher levels of working capital (due to higher value and levels of stored gas)
together with higher interest paid following the completion of Tauhara and the related reduction in
interest capitalisation.
The Board declared an interim dividend of 16 cents per share, up 2 cents per share or 14% on 1H24.
Shareholders will have the opportunity to participate in Contact’s dividend reinvestment plan at a 2%
discount.
Demand
Contact’s new long-term supply agreement with the New Zealand Aluminium Smelter (NZAS) began
on 1 July 2024 on improved pricing. Demand response was immediately activated by Meridian in
response to dry market conditions at the start of 1H25.
In February 2025, Contact entered a new 10-year agreement with Fonterra to supply ~415 GWh of
electricity a year to its Whareroa dairy site. Approximately two thirds of the volume will be new
demand from planned electrification in the dairy sector. This new demand will step up between
August 2026 and 2028 as transmission upgrades are completed.
“New summer-weighted demand aligns with Contact’s portfolio of renewable generation and is a great
fit for the solar projects Contact is developing with Lightsource bp. The deal is an example of how
electricity will play a key role supporting industry as it transitions from reliance on traditional fuels like
natural gas,” says Mr Fuge.
Renewable development
Contact is building renewable energy projects at pace to meet the needs of the energy transition. In
1H25, construction started on the 100MW battery at Glenbrook and on the 168MWp Kōwhai Park
solar farm in Christchurch. In November 2024, Contact confirmed its investment in the Wairakei
station extension and Te Mihi Stage 2 geothermal projects.
Contact’s new 51MW geothermal plant, Te Huka 3, came online in December 2024. Together with the
new 174MW Tauhara geothermal plant, Contact will be delivering ~1.9TWh a year of new geothermal
electricity to the New Zealand market. Renewable electricity generated by geothermal power plants
represented over 20% of New Zealand’s total electricity generation in 1H25, up from 17% in 1H24,
with Contact being the largest contributor to this uplift.
“Contact is investing to increase renewable generation capacity, across a range of technologies,
contributing both to energy market security and towards keeping wholesale electricity prices as low as
possible,” says Mr Fuge.
Decarbonising our portfolio
Contact had planned to close its remaining baseload gas generation plant, TCC, at the end of last
year. In response to public concern over security of supply in winter 2024, the plant will remain
available to be recalled over 2025, subject to a number of operational conditions.
“Ultimately, continuing to develop and build out our renewable energy pipeline is the key to the
continued decarbonisation of our portfolio,” said Mr Fuge.
In January 2025, Contact acquired an additional ~8% interest in Forest Partners, increasing its
investment in long-term sustainable forestry investment partnerships.
Contact Energy Ltd
3
Retail
In 1H25 Contact’s total retail connections were up ~39,000 on 1H24, with a focus on multi-product
customer growth.
Supporting our customers, we continue to see growth in our Time of Use ‘Good’ plans, with ~133,500
households now taking advantage of free off-peak energy, a 17 per cent increase in the past six
months. Since launching in August 2021, our customers have enjoyed 215 million hours of free
power. Contact also expanded its Hot Water Sorter programme to around 7,000 customers,
supporting the shift of more than 2MW of electricity load away from peak demand periods each day.
Contact is increasingly focused on supporting its customers in energy hardship and has removed
disconnection and reconnection fees under its Energy Wellbeing programme. The company has also
extended its partnership with Women’s Refuge covering the costs of power and broadband at its
refuges and safe houses nationwide.
Outlook
Looking ahead, Mr Fuge said the next six months would see Contact preparing for its proposed
combination with Manawa while continuing to deliver key milestones under its strategy to lead the
decarbonisation of New Zealand.
“We will continue to deliver the new renewable electricity projects and innovative supply
arrangements that are needed to support the energy transition in New Zealand. We have a strong
track record in both regards and an experienced team standing ready to deliver. This is all
underpinned by the strong performance of our underlying business, a range of capital options
available and the ongoing support of our shareholders,” said Mr Fuge.
1/ MORE INFORMATION
Investor enquiries Media enquiries
Shelley Hollingsworth Louise Wright
Investor Relations and Strategy Manager Head of Communications and Reputation
+64 27 227 2429 +64 21 840 313
investor.centre@contactenergy.co.nz media@contactenergy.co.nz
2/ WEBCAST
A webcast to support the interim results announcement will be held at 11am, NZ (New Zealand) time
on 17 February 2025. If you would like to attend the live presentation, please see the details below to
view the webcast off your chosen device:
Click here to register for the webcast: Contact Energy 1H25 Results webcast registration
Or access this link via our website: https://contact.co.nz/aboutus/investor-centre
i
Refer to slide 43 of the 2025 interim results presentation for a definition and reconciliation between statutory profit and the non-GAAP profit
measure earnings before net interest expense, tax, depreciation, amortisation, change in fair value of financial instruments (EBITDAF). From
FY24 Contact no longer reports impairments and write-offs within EBITDAF. These are now reported separately to better reflect underlying
performance. 1H24 figures restated accordingly.
ii
Refer to Note A3 of the interim financial statements for a definition and reconciliation between cash flow from operating activities and the non-
GAAP measure operating free cash flow. Operating free cash flow represents cash available to repay debt, to fund distributions to shareholders
and growth capital expenditure.
iii Refer to slide 44 of the 2025 interim results presentation for a reconciliation of the change in fair value of financial instruments.
---
2025
Interim Financial
Statements
2 Contact | Interim Financial Statements Contact | Interim Financial Statements 3
About these financial statements
FOR THE SIX MONTHS ENDED 31 DECEMBER 2024
These condensed interim financial statements are for Contact, a group made up of Contact Energy Limited, its
subsidiaries and its interests in associates and joint arrangements.
Contact Energy Limited is registered in New Zealand under the Companies Act 1993. It is listed on the New
Zealand stock exchange (NZX) and the Australian Securities Exchange (ASX) and has bonds listed on the NZX
debt market. Contact is an FMC reporting entity under the Financial Markets Conduct Act 2013.
Contact’s interim financial statements for the six months ended 31 December 2024 provide a summary of
Contact’s performance for the period and outline any significant changes to information reported in the
financial statements for the year ended 30 June 2024 (2024 Integrated Report). The interim financial
statements should be read with the 2024 Integrated Report.
Contact’s interim financial statements are prepared:
• in accordance with New Zealand generally accepted accounting practice (GAAP) and comply with NZ IAS 34
Interim Financial Reporting and IAS 34 Interim Financial Reporting.
• in millions of New Zealand dollars (NZD) unless otherwise noted.
• using the same accounting policies and significant estimates and critical judgments disclosed in the 2024
Integrated Report unless otherwise noted.
• with certain comparative amounts reclassified to conform to the current period’s presentation.
The interim financial statements were authorised on behalf of the Contact Energy Limited Board of Directors on
14 February 2025:
Robert McDonald Sandra Dodds
Chair Chair, Audit & Risk Committee
Statement of comprehensive income
FOR THE SIX MONTHS ENDED 31 DECEMBER 2024
$m Note
Unaudited
6 months ended
31 Dec 2024
Unaudited
6 months ended
31 Dec 2023
Audited
Year ended
30 June 2024
Revenue A1 1,707 1,306 2,863
Operating expenses A1 (1,263) (942) (2,188)
Net interest B4 (52) (20) (40)
Depreciation and amortisation C1 (130) (126) (255)
Asset impairment and write offs
- (8) (50)
Change in fair value of financial instruments D4 (61) 3 8
Profit/(loss) before tax 201 213 338
Tax expense (59) (60) (103)
Profit/(loss) 142 153 235
Items that may be reclassified to profit/(loss):
Change in hedge reserves (net of tax) D3 (5) (125) (176)
Comprehensive income 137 28 59
Profit/(loss) per share (cents) - basic and diluted 17.9 19.5 29.9
4 Contact | Interim Financial Statements
Contact | Interim Financial Statements 5
Statement of cash flows
FOR THE SIX MONTHS ENDED 31 DECEMBER 2024
$m Note
Unaudited
6 months ended
31 Dec 2024
Unaudited
6 months ended
31 Dec 2023
Audited
Year ended
30 June 2024
Receipts from customers 1,776 1,353 2,863
Payments to suppliers and employees (1,456) (1,027) (2,165)
Interest paid
(43) (9) (21)
Tax paid (74) (66) (97)
Operating cash flows 203 251 580
Purchase and construction of assets
(234) (262) (506)
Capitalised interest
(10) (35) (74)
Realised gains/losses on market derivatives
(13) (2) (6)
Investment in associates
(2) (2) (10)
Proceeds from sale of assets
- - 1
Investing cash flows (259) (301) (595)
Dividends paid B2 (114) (150) (248)
Proceeds from borrowings 427 526 592
Repayment of borrowings (266) (191) (238)
Financing costs
(4) (1) (2)
Financing cash flows 43 184 104
Net cash flow (13) 134 89
Add: cash at the beginning of the period 229 140 140
Cash at the end of the period 216 274 229
Statement of financial position
AT 31 DECEMBER 2024
$m Note
Unaudited
31 Dec 2024
Unaudited
31 Dec 2023
Audited
30 June 2024
Cash and cash equivalents 216 274 229
Trade and other receivables 213 219 275
Inventories 73 44 37
Intangible assets C1 70 116 43
Derivative financial instruments D1 110 40 68
Total current assets 682 692 652
Property, plant and equipment C1 5,053 4,771 4,933
Intangible assets C1 226 202 223
Inventories
65 37 40
Goodwill
214 214 214
Investment in associates
42 32 40
Derivative financial instruments D1 101 111 106
Total non-current assets 5,701 5,367 5,556
Total assets 6,383 6,059 6,208
Trade and other payables 318 290 356
Tax payable 12 26 34
Borrowings B3 482 356 359
Derivative financial instruments D1 102 125 152
Provisions 12 5 18
Total current liabilities 926 802 919
Borrowings B3 1,667 1,539 1,554
Derivative financial instruments D1 283 191 253
Provisions 313 256 294
Deferred tax 523 542 524
Other non-current liabilities 26 45 45
Total non-current liabilities 2,812 2,573 2,670
Total liabilities 3,738 3,375 3,589
Net assets 2,645 2,684 2,619
Share capital B1 2,092 2,008 2,021
Retained earnings 734 802 773
Hedge reserves (190) (134) (185)
Share-based compensation reserve 9 8 10
Shareholders' equity 2,645 2,684 2,619
6 Contact | Interim Financial Statements
Contact | Interim Financial Statements 7
Statement of changes in equity
FOR THE SIX MONTHS ENDED 31 DECEMBER 2024
$m Note
Share
capital
Retained
earnings
Hedge
reserves
Share-based
compensation
reserves
Shareholders'
equity
Balance at 1 July 2023 1,988 813 (9) 11 2,804
Profit/(loss) A2 - 153 - - 153
Change in hedge reserves (net of tax)
- - (125) - (125)
Change in share-based compensation
reserve B1 - - - (3) (3)
Change in share capital B1 20 - - - 20
Dividends paid B2 - (165) - - (165)
Unaudited balance at 31 December 2023 2,008 802 (134) 8 2,684
Profit/(loss) A2 - 82 - - 82
Change in hedge reserves (net of tax)
- - (51) - (51)
Change in share-based compensation
reserve B1 5 - - 7 12
Change in share capital B1 8 - - (5) 3
Dividends paid B2 - (110) - - (110)
Audited balance at 30 June 2024 2,021 773 (185) 10 2,619
Profit/(loss) A2 - 142 - - 142
Change in hedge reserves (net of tax) - - (5) - (5)
Change in share-based compensation
reserve B1 4 - - 3 7
Change in share capital B1 67 - - (4) 63
Dividends paid B2 - (181) - - (181)
Unaudited balance at 31 December 2024 2,092 734 (190) 9 2,646
A. Our performance
Notes to the interim financial statements for the six months ended 31 December 2024
A1. SEGMENTS
Contact reports activities under the Wholesale segment and the Retail segment. There have been no significant
changes to Contact’s operating segments in the current period.
The Wholesale segment includes revenue from the sale of electricity to the wholesale electricity market, to
Commercial & Industrial (C&I) customers, and to the Retail segment, less the cost to generate and/or purchase
the electricity and costs to serve and distribute electricity to C&I customers.
The results of Western Energy Services Limited are included in the Wholesale segment. The results of Contact
Energy Risk Limited have been allocated across the operating segments.
The Retail segment includes revenue from delivering electricity, natural gas, broadband, mobile and other
products and services to mass market customers less the cost of purchasing those products and services, and
the cost to serve and distribute electricity to customers. The Retail segment purchases electricity from the
Wholesale segment at a fixed price in a manner similar to transactions with third parties.
‘Unallocated’ includes corporate functions not directly allocated to the operating segments, including
transaction costs.
Realised gains/(losses) relating to risk management derivatives not in a hedge relationship are included in
‘Change in fair value of financial instruments’ within the Statement of Comprehensive Income but not in the
Segment results. In the Segment results they are included in wholesale electricity revenue or purchases within
EBITDAF.
These derivatives are ineligible to be designated into a hedge relationship for accounting purposes, however
they are commercial hedges and therefore are included within EBITDAF. Further information on hedge
accounting is included in note D5.
The below table provides a reconciliation between the Statement of Comprehensive Income and Segment
results.
$m
Statement of
Comprehensive
Income
Realised gains/(losses) on
risk management derivatives
not in a hedge relationship
Segment
results
6 months ended 31 December 2024
Revenue 1,707 (34) 1,673
Operating expenses (1,263) (6) (1,269)
Change in fair value of financial instruments (61) 40 (21)
6 months ended 31 December 2023
Revenue 1,306 3 1,309
Operating expenses (942) (5) (947)
Change in fair value of financial instruments 3 2 5
Year ended 30 June 2024
Revenue 2,863 4 2,867
Operating expenses (2,188) (4) (2,192)
Change in fair value of financial instruments 8 - 8
8 Contact | Interim Financial Statements
Contact | Interim Financial Statements 9
A2. SEGMENT RESULTS
The table below provides a breakdown of Contact’s revenue, expenses and earnings before interest, tax, depreciation and amortisation, asset impairment and write offs and changes in fair value of financial instruments (EBITDAF) by
segment, and a reconciliation from EBITDAF to profit/(loss) reported under NZ GAAP. EBITDAF is used to monitor performance and is a non-GAAP profit measure.
The definition of EBITDAF was updated in the 2024 financial year to exclude assets impairment and write off expenses from EBITDAF. Previously included in operating expenditure, these are now presented separately as its own line item
in the Statement of Comprehensive Income and Segment results (below EBITDAF). The change was made to provide greater focus on material asset impairment and write offs.
Unaudited 6 months ended 31 Dec 2024 Unaudited 6 months ended 31 Dec 2023 Audited year ended 30 June 2024
$m Wholesale Retail
Unallocated
Eliminations Total
Wholesale Retail
Unallocated
Eliminations Total
Wholesale Retail
Unallocated
Eliminations Total
Mass market electricity - 544 - (1) 543 - 524 - (1) 523 - 1,018 - (1) 1,017
C&I electricity - fixed price 130 - - - 130 112 - - - 112 252 - - - 252
C&I electricity - pass through 22 - - - 22 18 - - - 18 47 - - - 47
Wholesale electricity, net of hedging 840 - - - 840 548 - - - 548 1,321 - - - 1,321
Electricity-related services revenue 4 - - - 4 2 - - - 2 7 - - - 7
Inter-segment electricity sales 304 - - (304) - 280 - - (280) - 561 - - (561) -
Gas 16 52 - - 68 7 51 - - 58 8 96 - - 104
Steam 2 - - - 2 2 - - - 2 3 - - - 3
Geothermal services 4 - - - 4 3 - - - 3 12 - - - 12
Telco - 48 - - 48 - 39 - - 39 - 82 - - 82
Other income 8 4 - - 12 - 4 - - 4 12 10 - - 22
Total revenue 1,330 648 - (305) 1,673 972 618 - (281) 1,309 2,223 1,206 - (562) 2,867
Electricity purchases, net of hedging (581) (1) - - (583) (380) - - - (380) (990) (1) - - (991)
Electricity purchases - pass through (18) - - - (18) (13) - - - (13) (37) - - - (37)
Electricity related services cost (3) - - - (3) (3) - - - (3) (7) - - - (7)
Inter-segment electricity purchases - (304) - 304 - - (280) - 280 - - (561) - 561 -
Gas and diesel expenses (95) (13) - - (108) (60) (13) - - (74) (118) (23) - - (141)
Gas storage costs (7) - - - (7) 15 - - - 15 (15) - - - (15)
Carbon emissions costs (33) (5) - - (38) (29) (4) - - (33) (62) (7) - - (69)
Generation transmission & levies (16) - - - (16) (14) - - - (14) (29) - - - (29)
Electricity networks, levies & meter costs - fixed price (32) (243) - - (275) (28) (225) - - (253) (60) (449) - - (509)
Electricity networks, levies & meter costs - pass through (3) - - - (3) (4) - - - (4) (7) - - - (7)
Gas networks, transmission, meter & service costs (3) (28) - - (31) (3) (26) - - (29) (5) (51) - - (56)
Geothermal service costs (2) - - - (2) (2) - - - (2) (6) - - - (6)
Telco costs - (43) - - (43) - (34) - - (34) - (72) - - (72)
Other operating expenses (71) (36) (37) 1 (143) (64) (37) (23) 1 (123) (129) (74) (51) 1 (253)
Total operating expenses (864) (673) (37) 305 (1,269) (585) (619) (23) 281 (947) (1,465) (1,238) (51) 562 (2,192)
EBITDAF 466 (25) (37) - 404 387 (1) (23) - 362 758 (32) (51) - 675
Depreciation and amortisation
(130)
(126)
(255)
Net interest expense
(52)
(20)
(40)
Asset impairment and write offs
-
(8)
(50)
Change in fair value of financial instruments
(21)
5
8
Tax expense
(59)
(60)
(103)
Profit/(loss) 142 153 235
10 Contact | Interim Financial Statements
Contact | Interim Financial Statements 11
A3. FREE CASH FLOW
Free cash flow is a non-GAAP cash measure that shows the amount of cash Contact has available to distribute
to shareholders, reduce debt or reinvest in growing the business. A reconciliation from EBITDAF to NZ GAAP
operating cash flows and to free cash flow is provided below.
$m
Unaudited
6 months ended
31 Dec 2024
Unaudited
6 months ended
31 Dec 2023
Audited
Year ended
30 June 2024
EBITDAF 404 362 675
Tax paid (74) (66) (97)
Change in working capital, net of investing and
financing activities (80) (10) 31
Non-cash items included in EBITDAF (4) (18) (8)
Net interest paid, excluding capitalised interest (43) (9) (21)
Operating cash flows 203 259 580
Stay-in-business capital expenditure (65) (85) (156)
Operating free cash flow 138 174 424
Proceeds from sale of assets - - 1
Free cash flow 138 174 425
Operating free cash flow per share (cents) 17.4 22.1 53.9
There has been a reclassification between stay-in-business and growth capital expenditure to ensure that the
spend is classified according to which assets receive the most benefits under a revised scope of the Te Mihi
Stage 2 project. For the six months ended 31 December 2023 and the year ended 30 June 2024 stay-in-business
capital expenditure has been reclassified, increasing by $21 million and $46 million respectively, and therefore
also decreasing operating free cash flow by the same amounts. There is no impact to total capital expenditure.
A4. RELATED PARTY TRANSACTIONS
Contact’s related parties include the Directors, the Leadership Team (LT), Drylandcarbon One Limited
Partnership, Forest Partners Limited Partnership, Kowhai Park and Glorit Solar entities.
$m
Unaudited
6 months ended
31 Dec 2024
Unaudited
6 months ended
31 Dec 2023
Audited
Year ended
30 June 2024
Forest Partners Limited Partnership
Capital contributions (2) (2) (9)
Key management personnel
Directors' fees (1) (1) (1)
LT - salary and other short-term benefits (5) (4) (7)
LT - share-based compensation expense (1) (1) (2)
LT salary and other short-term benefits are the cash amount paid in the year. Directors and LT may purchase
goods and services from Contact for domestic purposes. For the LT this includes the staff discount available to
all eligible employees.
A5. AGS ONEROUS CONTRACT PROVISION
Contact recognises an onerous contract provision relating to the Ahuroa Gas Storage (AGS) contract with Flex
gas as the value of the contract is expected to be less than total contract payments. There are ongoing
discussions with Flexgas in relation to improving the capacity and operations of the AGS facility.
The provision is calculated as the difference between the contract payments and the estimated value received
from access to available storage over the remaining term of contract, discounted to present value using a
discount rate of 4.7% (31 December 2023: 4.4%, 30 June 2024: 4.7%).
The provision assumes that Contact has available storage of 2.1PJs (31 December 2023: 2.1 PJs, 30 June 2024:
2.1PJs) based on studies from the Technical Working Group in the prior year and actual performance of the
facility. The available storage assumption for the provision considers a range of possible scenarios over the
remaining term of the contract and is not an indication of Contact’s storage as at 31 December 2024.
The estimated value received from access to AGS storage is based on the ability for Contact to store gas in AGS,
and extract this for generating electricity when favourable to Contact.
$m
Unaudited
6 months ended
31 Dec 2024
Unaudited
6 months ended
31 Dec 2023
Audited
Year ended
30 June 2024
Opening provision balance (109) (116) (116)
Reassessment (impacts EBITDAF) - 35 35
Utilised/(increased) (impacts EBITDAF) 7 (7) (23)
Unwind of discount (impacts Interest) (2) (3) (5)
Closing balance (104) (90) (109)
A6. CONTINGENCIES
In the normal course of business, Contact is subject to inquiries, claims and investigations. There are no
material matters to disclose at 31 December 2024.
A7. SUBSEQUENT EVENTS
Contact acquired an additional 8% interest in Forest Partners Limited Partnership for $23 million on 31 January
2025, bringing total interests to 22%.
This is a non-adjusting event that is not reflected in the 31 December 2024 financial statements. The additional
interest will be recognised as an investment in associate on the balance sheet in the next reporting period.
12 Contact | Interim Financial Statements
Contact | Interim Financial Statements 13
B. Our funding
Notes to the interim financial statements for the six months ended 31 December 2024
B1. SHARE CAPITAL
Number $m
Balance at 1 July 2023 784,963,454 1,988
Share capital issued 2,542,748 20
Balance at 31 December 2023 787,506,202 2,008
Share capital issued 1,611,006 13
Balance at 30 June 2024 789,117,208 2,021
Share capital issued 8,829,329 71
Balance at 31 December 2024 797,946,537 2,092
B2. DIVIDENDS PAID
$m
Cents per
share
Unaudited
6 months ended
31 Dec 2024
Unaudited
6 months ended
31 Dec 2023
Audited
Year ended
30 June 2024
2023 Final dividend 21 - 165 165
2024 Interim dividend 14 - - 110
2024 Final dividend 23 181 - -
181 165 275
Comprising:
Cash dividends
114 150 248
Dividend reinvestment plan 67 15 27
On 14 February 2025 the Board declared an interim dividend of 16 cents per share to be paid on 18 March
2025.
B3. BORROWINGS
$m
Unaudited
31 Dec 2024
Unaudited
31 Dec 2023
Audited
30 June 2024
Lease obligations 50 46 47
Drawn bank facilities - - 26
Commercial paper 295 250 250
Retail bonds 550 650 650
Capital bonds 475 225 225
Export credit agency facility 22 29 25
USPP notes 224 224 224
Australian medium-term notes 434 434 434
Face value of borrowings 2,050 1,858 1,881
Deferred financing costs (13) (10) (9)
Total borrowings at amortised cost 2,037 1,848 1,872
Fair value adjustment on hedged borrowings 112 47 41
Carrying value of borrowings 2,149 1,895 1,913
Current 482 356 359
Non-current 1,667 1,539 1,554
All borrowings other than leases are Green Debt Instruments under Contact’s Green Borrowing Programme,
which has been certified by the Climate Bonds Initiative. At 31 December 2024 Contact remains compliant
with the requirements of the programme. Further information is available on the Sustainability section of
Contact’s website.
B4. NET INTEREST EXPENSE
$m
Unaudited
6 months ended
31 Dec 2024
Unaudited
6 months ended
31 Dec 2023
Audited
Year ended
30 June 2024
Interest expense on borrowings (58) (50) (105)
Interest expense on finance leases (1) (1) (3)
Unwind of discount on provisions (8) (7) (14)
Unwind of deferred financing costs (1) (1) (2)
Other interest - (1) (1)
Capitalised interest 10 35 74
Interest income 6 5 11
Net interest expense (52) (20) (40)
14 Contact | Interim Financial Statements
Contact | Interim Financial Statements 15
C. Our assets
Notes to the interim financial statements for the six months ended 31 December 2024
C1. PROPERTY, PLANT AND EQUIPMENT AND INTANGIBLE ASSETS
Property, plant and equipment
$m
Unaudited
31 Dec 2024
Unaudited
31 Dec 2023
Audited
30 June 2024
Opening balance 4,933 4,615 4,615
Additions 234 273 587
Disposals - (4) (44)
Depreciation charge (114) (113) (226)
Closing balance 5,053 4,771 4,933
Included within additions is capitalised interest of $10 million (31 December 2023: $35 million, 30 June 2024:
$74 million) in relation to, Tauhara, Te Huka Unit 3, Te Mihi Stage 2 project and associated steamfields, and
the Glenbrook Battery.
Intangibles
$m
Unaudited
31 Dec 2024
Unaudited
31 Dec 2023
Audited
30 June 2024
Opening balance 266 235 235
Additions 46 102 125
Disposals - (6) (65)
Amortisation charge (16) (13) (29)
Closing balance 296 318 266
Current 70 116 43
Non-current 226 202 223
Contracted capital commitments
$m
Unaudited
31 Dec 2024
Unaudited
31 Dec 2023
Audited
30 June 2024
Contracted capital expenditure 442 252 209
Carbon forward contracts
97 89 120
Closing balance 539 341 329
Due within 12 months 283 257 195
Due beyond 12 months 256 84 134
16 Contact | Interim Financial Statements
Contact | Interim Financial Statements 17
D. Financial risks
Notes to the interim financial statements for the six months ended 31 December 2024
D1. SUMMARY OF DERIVATIVE FINANCIAL INSTRUMENTS
A summary of derivatives and the impact on Contact’s financial position is provided below grouped by type of hedge relationship. There were no changes in the valuation processes, valuation techniques, or types of inputs used in the fair
value measurements during the period. Refer to the 2024 Integrated Report for information about fair value hierarchy of our inputs. In the two tables below, 31 December 2024 and 31 December 2023 numbers are unaudited, whereas 30
June 2024 numbers are audited.
Fair value hedge Cash flow and fair value hedge Cash flow hedge No hedge relationship
IRS CCIRS IRS Electricity derivatives Foreign exchange contracts Electricity derivatives
$m 31 Dec 24 31 Dec 23 30 Jun 24 31 Dec 24 31 Dec 23 30 Jun 24 31 Dec 24 31 Dec 23 30 Jun 24 31 Dec 24 31 Dec 23 30 Jun 24 31 Dec 24 31 Dec 23 30 Jun 24 31 Dec 24 31 Dec 23 30 Jun 24
Financial year of maturity 2025-30 2025-29 2025-29 2026-31 2026-31 2026-31 2025-31 2024-31 2025-31 2025-39 2024-39 2025-39 2025-28 2024-26 2025-26 2025-45 2024-28 2025-28
Notional amount of derivatives 1,025 875 875 658 658 658 2,000 1,835 1,885
GWh
13,932
GWh
15,253
GWh
14,644 247 137 74
GWh
26,016
GWh
1,799
GWh
1,614 h
Carrying amount of hedged borrowings (1,042) (871) (862) (753) (709) (712) - - - - - - - - - - - -
Fair value adjustments to borrowings (17) 4 13 (95) (51) (54) - - - - - - - - - - - -
Fair value of derivatives - asset 21 15 6 95 58 61 15 37 44 32 17 22 13 - 1 35 24 40
Fair value of derivatives - liability (5) (20) (20) (2) (9) (10) (45) (27) (11) (288) (218) (317) (1) (4) (3) (44) (37) (44)
D2. CHANGE IN FAIR VALUE OF DERIVATIVES IN THE STATEMENT OF COMPHENSIVE INCOME - UNREALISED
Fair value hedge Cash flow and fair value hedge Cash flow hedge No hedge relationship
IRS CCIRS IRS Electricity derivatives Foreign exchange contracts Electricity derivatives
$m Note
31 Dec 24
31 Dec 23 30 Jun 24
31 Dec 24
31 Dec 23 30 Jun 24
31 Dec 24
31 Dec 23 30 Jun 24
31 Dec 24
31 Dec 23 30 Jun 24
31 Dec 24
31 Dec 23 30 Jun 24
31 Dec 24
31 Dec 23 30 Jun 24
Change in fair values recognised in:
- Change in fair value of financial
instruments (Profit/(loss)) D4 - - - - 1 1 2 2 4 - - - - - - (8) 4 6
- Hedge effectiveness recognised
in OCI D3 - - - 1 (2) (2) (61) (44) (14) (13) (98) (189) 12 (4) (2) - - -
- Amounts reclassified to
profit/(loss) or balance sheet D3 - - - - - - (4) - (10) 52 (29) (32) 2 1 1 - - -
- Premiums derecognised in
receivables - - - - - - - - - - - - - - - 3 3 10
Total unrealised movement - - - 1 (1) (1) (63) (42) (20) 39 (127) (221) 14 (3) (1) (5) 7 16
Change in fair value of financial instruments recognised in profit/(loss) also includes realised gains/(losses). Cash flow hedge reserves and the total change in fair value recognised in profit/(loss) and has been reconciled in notes D3 and D4.
18 Contact | Interim Financial Statements
Contact | Interim Financial Statements 19
D3. MOVEMENT IN HEDGE RESERVE
$m Note
Unaudited
31 Dec 2024
Unaudited
31 Dec 2023
Audited
30 June 2024
Opening balance
(185) (9) (9)
Effective portion of cash flow hedges D2 (61) (148) (207)
Transferred to profit/loss or balance sheet D2 50 (28) (41)
Transferred to deferred tax
7 48 69
Amortisation of hedge reserve
(1) 3 3
Closing balance (190) (134) (185)
D4. CHANGE IN FAIR VALUE OF FINANCIAL INSTRUMENTS IN PROFIT/(LOSS)
$m Note
Unaudited
31 Dec 2024
Unaudited
31 Dec 2023
Audited
30 June 2024
Within EBITDAF:
Realised gains/(losses) on risk management
derivatives A1 (40) (2) -
Below EBITDAF:
Realised gains/(losses) on market derivatives
(14) (2) (3)
Unrealised gains/(losses) on unhedged derivatives D1 (8) 4 6
Unrealised gains/(losses) - hedge ineffectiveness D1 2 3 5
Total below EBITDAF per segment results A1 (21) 5 8
Change in fair value of financial instruments (61) 3 8
Realised gains/(losses) on risk management derivatives are higher for the 6 months period 31 December 2024
compared to prior reporting periods due to the recognition of realised losses of the new long term electricity
derivative with New Zealand Aluminium Smelter (NZAS).
The new long term electricity derivative with NZAS is not eligible for hedge accounting, therefore in the
Statement of Comprehensive Income, realised gains/(losses) relating to the derivative are required to be
recognised in Change in fair value of financial instruments instead of Revenue. Further information on hedge
accounting is discussed in D5.
The Realised gain/(loss) lines in the table above are unfavourable because overall, the fixed contract price for
the electricity derivatives have been lower than wholesale electricity prices during the reporting period.
D5. ELECTRICTY DERIVATIVES
Contact uses a range of derivatives contracts to manage interest rate risks, foreign exchange risks and
commodity price risks, including electricity prices. Where possible, hedge accounting is applied under NZ IFRS 9
and the derivatives are designated into fair value or cash flow hedge relationships.
Hedge accounting
Where eligible, Contact designates electricity derivatives into a cash flow hedge against forecast electricity sales
and purchases. Unrealised gains or losses that are hedge effective are recognised in cash flow hedge reserves
until the derivatives are settled and at such time, the unrealised gains or losses are reclassified to profit/(loss).
Not in a hedge relationship
Some electricity derivatives may not be eligible for hedge accounting, including when they include termination
options, have variable volume structures (e.g solar power purchase agreements), or they have been entered
into for market making or trading. Unrealised gains or losses relating to these derivatives are recognised in
profit/loss within “Change in fair value of financial instruments” below EBITDAF.
Contact uses discounted cash flow valuations to fair value the electricity derivatives at each reporting period. A
key variable used in these valuations are future wholesale electricity prices. Therefore, the fair value of the
electricity price derivatives will change depending on changes to future wholesale electricity prices, which may
cause significant volatility to profit/(loss) where these derivatives are not in a hedge relationship.
The table below summarises the impact on profit/(loss) from possible changes in fair value of these derivative
(unrealised gains/(losses) due to change in forward wholesale electricity prices. This analysis assumes a flat
percentage change of forward wholesale electricity prices across the remaining term of the contracts and all
other variables were held constant.
Favourable/(unfavourable) impact on
profit/(loss) (post tax)
Unaudited
6 months ended
31 Dec 2024
Unaudited
6 months ended
31 Dec 2023
Audited
Year ended
30 June 2024
+10% forward wholesale electricity prices (48) 3 2
-10% forward wholesale electricity prices 44 (3) (3)
Profit/(loss) is subject to more volatility for the 6 months ended 31 December 2024 and in future periods, due
to the recognition of the new long term electricity derivative with NZAS. Although the contract is a commercial
hedge providing a fixed price in real terms on future generation revenue, it is ineligible to be designated into a
hedge relationship for accounting purposes under NZ IFRS 9 due to the ability for NZAS to terminate the
contract after 10 years.
20 Contact | Interim Financial Statements
Contact | Interim Financial Statements 21
To the shareholders of Contact Energy Limited
Report on the review of the interim financial
statements
Conclusion
We have reviewed the condensed interim financial
statements of Contact Energy Limited (the “Company”) and
its subsidiaries (together “the Group”) on pages 2 to 19 which
comprise the consolidated statement of financial position as
at 31 December 2024, and the consolidated statement of
comprehensive income, consolidated statement of changes in
equity and consolidated statement of cash flows for the six
month period ended on that date, and explanatory notes.
Based on our review, nothing has come to our attention that
causes us to believe that the accompanying interim financial
statements on pages 2 to 19 of the Group do not present
fairly, in all material respects, the financial position of the
Group as at 31 December 2024, and its financial performance
and its cash flows for the six month period ended on that
date, in accordance with New Zealand Equivalent to
International Accounting Standard 34: Interim Financial
Reporting (NZ IAS 34) and International Accounting Standard
34: Interim Financial Reporting (IAS 34).
This report is made solely to the Company’s shareholders, as a
body. Our review has been undertaken so that we might state
to the Company’s shareholders those matters we are required
to state to them in a review report and for no other purpose.
To the fullest extent permitted by law, we do not accept or
assume responsibility to anyone other than the Company and
the Company’s shareholders as a body, for our review
procedures, for this report, or for the conclusion we have
formed.
Basis for conclusion
We conducted our review in accordance with NZ SRE 2410
(Revised) Review of Financial Statements Performed by the
Independent Auditor of the Entity. Our responsibilities are
further described in the Auditor’s responsibilities for the
review of the financial statements section of our report. We
are independent of the Group in accordance with the relevant
ethical requirements in New Zealand relating to the audit of
the annual financial statements, and we have fulfilled our
other ethical responsibilities in accordance with these ethical
requirements.
Ernst & Young provides services to the Group in relation to
trustee reporting, market remuneration surveys, due
diligence in relation to proposed Manawa acquistion and
other assurance services relating to the Company’s Global
Reporting Initiative disclosures, greenhouse gas emissions
reporting and Green Borrowings Programme reporting.
Partners and employees of our firm may deal with the Group
on normal terms within the ordinary course of trading
activities of the business of the Group. We have no other
relationship with, or interest in, the Group.
Directors’ responsibility for the interim financial
statements
The directors are responsible, on behalf of the Company, for
the preparation and fair presentation of the interim financial
statements in accordance with NZ IAS 34 and IAS 34 and for
such internal control as the directors determine is necessary
to enable the preparation and fair presentation of the interim
financial statements that are free from material
misstatement, whether due to fraud or error.
Auditor’s responsibilities for the review of the
interim financial statements
Our responsibility is to express a conclusion on the interim
financial statements based on our review. NZ SRE 2410
(Revised) requires us to conclude whether anything has come
to our attention that causes us to believe that the interim
financial statements, taken as a whole, are not prepared in all
material respects, in accordance with NZ IAS 34 and IAS 34.
A review of interim financial statements in accordance with
NZ SRE 2410 (Revised) is a limited assurance engagement. We
perform procedures, consisting of making enquiries, primarily
of persons responsible for financial and accounting matters,
and applying analytical and other review procedures. The
procedures performed in a review are substantially less than
those performed in an audit conducted in accordance with
International Standards on Auditing (New Zealand) and
consequently do not enable us to obtain assurance that we
would become aware of all significant matters that might be
identified in an audit. Accordingly, we do not express an audit
opinion on those interim financial statements.
The engagement partner on the review resulting in this
independent auditor’s review report is Lianne Austin.
Chartered Accountants
Wellington
14 February 2025
Corporate directory
Board of Directors
Robert McDonald (Chair)
Sandra Dodds
David Gibson
Jon Macdonald
David Smol
Rukumoana Schaafhausen
Elena Trout
Leadership team
Mike Fuge
Chief Executive Officer
Chris Abbott
Chief Corporate Affairs Officer
Jack Ariel
Major Projects Director
Jan Bibby
Chief People Experience Officer
Matt Bolton
Transition Director
John Clark
Chief Generation Officer
Dorian Devers
Chief Development and Major Projects Officer
Matthew Forbes
Chief Financial Officer (Acting)
Michael Robertson
Chief Retail Officer (Acting)
Tighe Wall
Chief Digital Officer
Registered office
Contact Energy Limited
Harbour City Tower
29 Brandon Street
Wellington 6011
New Zealand
T +64 4 499 4001
Find us on Facebook, Twitter, LinkedIn and
Youtube by searching for Contact Energy
Company numbers
NZ Incorporation 660760
ABN 68 080 480 477
Auditor
Ernst & Young
PO Box 490
Wellington 6011
Registry
Change of address, payment instructions
and investment portfolios can be viewed
and updated online:
investorcentre.linkmarketservices.co.nz
investorcentre.linkmarketservices.com.au
New Zealand Registry
MUFG Corporate Markets (formerly Link
Market Services)
PO Box 91976, Auckland 1142
Level 30, PWC Tower
15 Custom Street West, Auckland 1010
contactenergy@linkmarketservices.co.nz
T +64 9 375 5998
Australian Registry
MUFG Corporate Markets (formerly Link
Market Services)
Locked Bag A14, Sydney South, NSW 1235
680 George Street, Sydney, NSW 2000
contactenergy@linkmarketservices.com.au
T +61 2 8280 7111
Company secretary
Kirsten Clayton
General Counsel and Company Secretary
Investor relation enquiries
Shelley Hollingsworth
Head of Corporate Finance (Acting)
investor.centre@contactenergy.co.nz
Sustainability enquiries
Taria Tahana
Head of Sustainability
sustainability@contactenergy.co.nz
Independent Auditor’s review report
---
Results announcement
Results for announcement to the market
Name of issuer Contact Energy Limited
Reporting Period 6 months to 31 December 2024
Previous Reporting Period 6 months to 31 December 2023
Currency NZD
Amount (000s) Percentage change
Revenue from continuing
operations
$1,707,116 +30.7%
Total Revenue $1,707,116 +30.7%
Net profit/(loss) from
continuing operations
$142,392 -7.2%
Total net profit/(loss) $142,392 -7.2%
Interim/Final Dividend
Amount per Quoted Equity
Security
$0.16000000
Imputed amount per Quoted
Equity Security
$0.05444444
Record Date 25/02/2025
Dividend Payment Date 18/03/2025
Current period Prior comparable period
Net tangible assets per
Quoted Equity Security
$2.68 $2.74
A brief explanation of any of
the figures above necessary
to enable the figures to be
understood
Authority for this announcement
Name of person
authorised
to make this announcement
Kirsten Clayton, General Counsel & Company Secretary
Contact person for this
announcement
Shelley Hollingsworth, Investor Relations & Strategy Manager
Contact phone number +64 27 227 2429
Contact email address shelley.hollingsworth@contactenergy.co.nz
Date of release through MAP
17/02/2025
Audited financial statements accompany this announcement.
---
Distribution Notice
Section 1: Issuer information
Name of issuer Contact Energy Limited
Financial product name/description Ordinary shares
NZX ticker code CEN
ISIN (If unknown, check on NZX
website)
NZCENE0001S6
Type of distribution
(Please mark with an X in the
relevant box/es)
Full Year Quarterly
Half Year X Special
DRP applies X
Record date 25/02/2025
Ex-Date (one business day before the
Record Date)
24/02/2025
Payment date (and allotment date for
DRP)
18/03/2025
Total monies associated with the
distribution
$127,671,446
(797,946,537 shares @ $0.16 / share)
Source of distribution (for example,
retained earnings)
Operating Free Cash Flow
Currency NZD
Section 2: Distribution amounts per financial product
Gross distribution $0.21444444
Gross taxable amount $0.21444444
Total cash distribution $0.16000000
Excluded amount (applicable to listed
PIEs)
N/A
Supplementary distribution amount $0.02470588
Section 3: Imputation credits and Resident Withholding Tax
Is the distribution imputed
Fully imputed
Partial imputation
No imputation
If fully or partially imputed, please
state imputation rate as % applied
25%
Imputation tax credits per financial
product
$0.05444444
Resident Withholding Tax per
financial product
$0.01632222
Section 4: Distribution re-investment plan (if applicable)
DRP % discount (if any)
2%
Start date and end date for
determining market price for DRP
24/02/2025 28/02/2025
Date strike price to be announced (if
not available at this time)
06/03/2025
Specify source of financial products to
be issued under DRP programme
(new issue or to be bought on market)
New issue
DRP strike price per financial product
Not available at this time
Last date to submit a participation
notice for this distribution in
accordance with DRP participation
terms
26/02/2025
Section 5: Authority for this announcement
Name of person
authorised to make
this announcement
Kirsten Clayton, General Counsel & Company Secretary
Contact person for this
announcement
Shelley Hollingsworth, Investor Relations & Strategy
Manager
Contact phone number +64 27 227 2429
Contact email address shelley.hollingsworth@contactenergy.co.nz
Date of release through MAP
17/02/2025
---
1
2025 interim results presentation
17 February 2025
Six months ended 31 December 2024
2
Disclaimer and important information
This presentation contains summary information and statements about Contact and its
businesses and activities as at the date of this presentation. The information is not held
out as being complete or exhaustive, nor does it contain all the information which a
prospective investor may require in evaluating a possible investment in Contact.
While all reasonable care has been taken in compiling this presentation, neither Contact
nor any of its directors, employees, shareholders nor any other person gives any
representation as to the accuracy or completeness of this information or accepts any
liability for any errors or omissions.
Contact recommends that you read this presentation in conjunction with its market
announcements and the materials attached to those announcements, and in particular
the market announcements and materials it released on the date of this presentation.
These are available on the NZX website (at www.nzx.com), the ASX website (at
www.asx.com.au) and on Contact's website (at www.contact.co.nz).
This presentation may contain certain forward-looking statements with respect to a
variety of matters. All such forward-looking statements involve known and unknown risks,
significant uncertainties, assumptions, contingencies, and other factors, many of which
are outside the control of Contact, which may cause the actual results or performance of
Contact to be materially different from any future results or performance expressed or
implied by such forward-looking statements. Such forward-looking statements speak only
as of the date of this presentation. Except as required by law or regulation (including the
NZX Listing Rules and the ASX Listing Rules), Contact undertakes no obligation to
update these forward-looking statements for events or circumstances that occur
subsequent to the date of this presentation or to update or keep current any of the
information contained herein. Any estimates or projections as to events that may occur in
the future (including projections of revenue, expense, net income and performance) are
based upon the best judgement of Contact from the information available as of the date
of this presentation.
EBITDAF, free cash flow and operating free cash flow are financial measures that are
“non-GAAP (generally accepted accounting practice) financial information” under
Guidance Note 2017: ‘Disclosing non-GAAP financial information’ published by the New
Zealand Financial Markets Authority, “non-IFRS financial information” under ASIC
Regulatory Guide 230: ‘Disclosing non-IFRS financial information’ and “non-GAAP
financial measures” within the meaning of Regulation G under the U.S. Exchange Act of
1934.
Such financial information and financial measures (including EBITDAF, free cash flow
and operating free cash flow) do not have standardised meanings prescribed under New
Zealand equivalents to International Financial Reporting Standards (“NZ IFRS”),
Australian Accounting Standards (“AAS”) or International Financial Reporting Standards
(“IFRS”) and therefore, may not be comparable to similarly titled measures presented by
other entities, and should not be construed as an alternative to other financial measures
determined in accordance with NZ IFRS, AAS or IFRS accounting practice) measures.
Information regarding the usefulness, calculation and reconciliation of these measures is
provided in the supporting material.
This presentation does not constitute legal, financial, tax, accounting, investment or other
advice. Further, this presentation does not constitute a recommendation or offer of
financial products for subscription, purchase or sale, or an invitation or solicitation for
such offers, and may not be relied on in connection with any purchase of a Contact
security. Any person who is considering an investment in Contact should obtain
independent professional advice prior to making an investment decision, and should
make their investment decision having regard to their own objectives, financial situation,
circumstances and needs.
Numbers in the presentation have not all been rounded and might not appear to add.
All references to $ are New Zealand dollar unless stated otherwise.
Alltrademarks, service marks andcompany namesare thepropertyoftheir respective
owners. All company, product and service names used in this presentation are for
identification purposes only. Use of these names, trademarks and brands does not imply
endorsement or that they are or will be customers of Contact and reflects public
announcements of intention only.
3
Presenting today
Mike Fuge
Chief Executive Officer
Matt Forbes
Chief Financial Officer (Acting)
4
1H25 highlights / Mike Fuge, CEO 5 - 13
Market context / Mike Fuge, CEO 15 - 18
Financial results and outlook / Matt Forbes, Acting CFO 20 - 32
2
3
1
Agenda
Supporting materials 35 - 47
4
5
FY25 highlights to date
Construction underway on
100MW grid-scale battery
Entered Manawa
Scheme of Arrangement
Annual dividend
uplift of 4cps
(+2cps August 2024 FY24 final,
+2cps today – FY25 interim)
Te Huka III
51MW geothermal power
stationonline
Investment confirmed
Te Mihi Stage 2
101MW geothermal power station
and Wairakei extension
~415 GWh supply
agreement supporting
electrification
Hot Water Sorter
programme expanded, shifting ~2MW
load from peak demand periods
Supported the market
by facilitating access to ~3.5PJ
Methanex
gas in winter 2024
Construction underway on 168MWp
Kōwhai Park Solar farm
in joint venture with
Glenbrook BESS
Taranaki
Combined Cycle
gas plant made
available for 2025
Continued
representation within
Dow Jones
Sustainability
Asia Pacific Index
Contact included in MSCI
Global Standard Index
in February rebalance
5
6
Executive team changes
Contact Energy has announced several key executive changes
Mike Fuge
Chief Executive Officer
key
Executive positions unchanged
Consolidation and/or newly established
•Development and Major Projects
roles consolidated.
•Digital and Information Technology
roles consolidated.
•Integration Office established led by
Transition Director – preparing for
potential acquisition of Manawa.
•Recruitment process underway for
Chief Financial Officer and Chief
Retail Officer.
Jan Bibby
Chief People Experience
Officer
Chris Abbott
Chief Corporate Affairs
Officer
John Clark
Chief Generation Officer
Jack Ariel
Major Projects Director
(Retiring February 2025)
Tighe Wall
Chief Technology Officer
Matt Bolton
Transition Director
Dorian Devers
Chief Development and
Major Projects Officer
Key Updates
7
Six months ended 31
December 2024 (1H25)
Six months ended 31
December 2023 (1H24)
ReportedAgainst reported
EBITDAF $404m↑12% from $362m
Profit$142m↓7% from $153m
Profit per share17.9 c↓8% from 19.5c
Operating free cash flow
1
$138m ↓21% from $174m
Operating free cash flow
per share
1
17.4 c↓21% from 22.1c
Dividend declared
(interim)
$128m↑16% from $110m
Dividend declared per
share (interim)
16.0 c↑14% from 14.0 c
Stay-in-business (SIB)
capital expenditure
(cash)
$65m↓24% from $85m
Growth capital
expenditure (cash)
2
$179m↓16% from $212m
1H25 was characterised by hydro inflow and wholesale electricity
price volatility with the market swinging between dry and wet hydro
conditions. The market observed:
•Historically low hydro inflows in July and early August (following
a dry 2H24) resulting in a rapid reduction in hydro storage
(reaching the 3rd lowest national storage level in 80 years).
•Continued contraction in gas availability (gas production was
~30PJ lower in CY24 compared to CY23).
•Spot and forward wholesale electricity prices responded to fuel
scarcity conditions, peaking at historic highs in early August.
•Rapid unwind of conditions in the second quarter with several
large inflow events from mid-August and the signing of major
gas supply contracts between Contact and Genesis with
Methanex.
•Resultant rapid decline in spot prices and increased hydro
storage volumes which finished the period well above average.
Summary of key financial performance measures
Delivering renewable investment while supporting
security of supply
Contact took a range of proactive steps to support security of
supply through the first quarter including:
•Entered new contract with NZAS starting 1 July 2024
alongside a demand response agreement with a mechanism
to reduce load by up to 46MW (activated July 2024).
•Entered gas purchase agreement with Methanex in August
2024 that saw Contact buy ~3.5PJ of gas.
•Tauhara brought online in May 2024, providing consistent
baseload generation improving supply / demand dynamics.
•Increased use of TCC to maximise the efficient use of
Contact’s gas supplies.
As market conditions changed in the second quarter, Contact:
•Utilised AGS to store gas, maximising its future utility and
avoiding uneconomic thermal generation.
•Brought Te Huka 3 online in December 2024.
Market
1
Refer to slide 28 for a reconciliation of operating free cash flow.
2
Includes capitalised interest.
3
This is a through-the-cycle measure in a balanced market and is shown on a 2025 real basis. Prices actually achieved are a function of the market at a point in time.
1H25
•Lines cost increases to take effect from 1 April 2025.
•Gas supplies / production are expected to continue to reduce
as major domestic fields reach end of life.
•Rising fixed costs at ageing thermal plants (which need to be
recovered over less generation) and the rapid build out of
intermittent renewable plant mean risk management costs and
price volatility continue to rise.
•Increases to wind construction costs appear to be structural.
•Contact’s view of long-term wholesale prices is $115
to125/MWh.
3
Medium term
Orderly build-out of renewable generation with multiple
projects committed and commissioned in 1H25:
•Committed to Wairakei redevelopment and extension
projects, securing the long-term future of geothermal on
the Wairakei field.
•Committed to build Kōwhai Park solar (168MWp).
•Committed to Glenbrook BESS (100MW / 200MWh).
•Completed Tauhara commissioning and brought Te Huka
3 online, representing ~1.9TWh p.a. new geothermal
output on a full year basis.
•TCC made available for 2025 if needed by the market.
8
Key strategic highlights from 1H25
New geothermal station – Te Huka 3 –
online from December 2024 (51 MW)
Construction underway on Glenbrook
BESS (100MW / 200MWh).
Construction underway on Kōwhai Park
solar farm in Christchurch (168MWp).
Investment confirmed in new 101MW
Te Mihi Stage 2 geothermal plant and
Wairakei extension, securing the long-
term future of geothermal production
on the Wairakei field.
Invited interest in market-wide,
intra-day storage service for a
potential 100MW BESS
2
at
Stratford (a consented site).
TCC to be kept available in 2025,
if required by the market, to
support New Zealand's security
of supply.
Purchased additional ~8%
interest (taking total to 22%) in
Forest Partners (January 2025),
increasing investment in long-
term sustainable forestry.
Tauhara-backed PPAs and new long-
term NZAS contract commenced.
Progress continues towards a final
investment decision on food grade CO
2
project at Ohaaki.
Signed a summer-weighted 10-year
electricity supply agreement with
Fonterra for ~415 GWh p.a.
1
Underlying demand showing signs of
structural growth.
Objective
1H25
highlights
Attract new industrial demand with
globally competitive renewables
Build renewable generation and
flexibility on the back of new demand
Lead an orderly transition to
renewables
Create New Zealand's leading energy and
services brand to meet more of our customers’
needs
Grow
demand
Grow renewable
development
Decarbonise
our portfolio
Create outstanding
customer experiences
Total Retail closing connections +39k on 1H24,
with a focus on multiproduct customer growth
(+16k) while maintaining targeted retail channel
sales volume.
Scaled time of use ‘Good’ plans (+54k) and
Telco connections up (+23k) on 1H24.
Expansion of Hot Water Sorter programme to
~7k customers, shifting ~2MWper day out of
peak demand periods.
Removed disconnection and reconnection fees
under Contact’s Energy Wellbeing programme.
Energy Retailer of the Year finalist
(for the third consecutive year).
1
Approximately two thirds of this volume represents new demand for electricity in the dairy sector. This new demand will step up between August 2026 and 2028 as transmission upgrades are completed.
2
Battery Energy Storage System (BESS).
9
Commissioning completed in December 2024 on
the first of four replacement turbines at Roxburgh
hydro dam.
Process safety upgrade completed at Te Mihi
during its four yearly statutory outage in October
2024.
Launched Contact’s new Trading and Risk
Management platform (Trade Deal Capture).
Launched new versions of Contact’s customer
mobile app and online self-service experiences
for Retail (85% of all service interactions are now
through these channels).
Included in Dow Jones Sustainability (DJSI)
Asia Pacific Index for the third consecutive year.
Rated “A – Leader” and ranked second out of 61
New Zealand companies in Forsyth Barr’s
Carbon & ESG Ratings for 2024.
Extended partnership with Women's Refuge for
a further three years.
Issued $250m of Green Capital bonds.
Create long-term value through our strong
performance across a broad set of
environmental, social and governance factors
Continuously improving our operations
through innovation and digitisation
Create a flexible and high-performing
environment for NZ's top talent
Our ESG
commitment
Operational
excellence
Transformative
ways of working
Wellbeing Award winner, NZ Energy
Excellence Awards, for Contact’s Skin
Checks Wellbeing initiative.
Launched Leadership Programme (Mau
Taniwha Mauri Ora) for both existing and
emerging leaders.
Received continued Wellbeing Tick
Accreditation.
Enhanced KiwiSaver and broad-based
Contact share scheme (Contact Share)
benefits for employees.
Objective
1H25
highlights
1H25 delivery supported by enablers
10
Demand: Industrial process heat electrifies
Contact is helping to lead the charge with several major, innovative, supply agreements
Industrial / primary sector (existing load):
Innovative, economic contract structures
Dairy / primary sector decarbonisation:
Fonterra – Electrode boiler replacement
Industrial decarbonisation:
NZ Steel – Electric Arc Furnace
Uncertainty about fuel availability is accelerating the transition for customers currently using natural gas.
Existing industrial customers are also adopting demand response as a means of lowering energy costs.
•Expected online early CY2026. Contact supplying 30MW.
•In light of rising peak price volatility, the off-peak
winter structure helped unlock electrification.
•Fonterra is undertaking a staged energy transformation
that includes the installation of electrode boilers at
selected sites.
•Contact has entered a new 10-year agreement to supply
~415GWh p.a. to Fonterra’s Whareroa dairy site.
•Agreement begins August 2026 at ~140GWh p.a. to
cover existing demand. Steps up over time to reach
~415GWh p.a. in 2028 to support the electrification of the
site.
•The shape of the supply agreement is weighted to
summer, well aligned to Contact’s renewable
generation portfolio.
Morning
peak
Evening
peak
MW
30 MW
4
Hours
4
Hours
•Existing industrial customers across a range of sectors
are now actively exploring demand response and other
contract shaping mechanisms.
•Contact is engaged in developing a number of bespoke
solutions to meet the changing needs of customers.
•The shared benefits of demand response, between
supplier and customer, have the potential to support
the retention of significant existing industrial
demand.
11
Tauhara
Renewable builds: Online and underway
May 2024
Online date
$924m
1
Total Investment
174MW
Installed Capacity
1,450GWh
Estimated Annual
Output
~200,000
Dec 2024
Online date
$300m
1
Total Investment
51MW
Installed Capacity
430GWh
Estimated Annual
Output
~60,000
Equivalent homes powered
Projects Online
Te Huka 3
Projects Under
Construction
Glenbrook BESS
2
(Auckland)
Te Mihi Stage 2
(Taupō)
Kōwhai Park Solar
(Christchurch)
Announcement Date
1 July 202416 Aug 202413 Nov 2024
Glenbrook
BESS
2
Kōwhai Park
Solar
Te Mihi Stage 2
Geothermal
100MW168MWp | 275GWh101MW | 830GWh
Installed capacity /
Estimated annual output
Expected online
date
On track
Q1 CY2026
On track
Q2 CY2026
On track
Q3 CY2027
1
Total under current approvals.
Equivalent homes powered
2
Battery Energy Storage System.
12
Southland
Renewable builds: Next in line priority sites
Southland Wind
Glorit Solar
Stratford Solar
Focusing on advancing next development options
Glorit
FY26
Expected FID
date
300GWh
Estimated Annual
Output
180MWp
Estimated
Capacity
FY26
Earliest expected
FID date
330MW
Estimated
Capacity
1,200GWh
Estimated Annual
Output
Stratford
Existing
substation
FY26
Earliest expected
FID date
300GWh
Estimated Annual
Output
Note: Additional North Island BESS
1
options under consideration are not shown in the diagram above.
1
Battery Energy Storage System.
180MWp
Estimated
Capacity
Consent
lodged
Panel
Convened
Assessment
underway
Status
Consenting activities
underway
Status
Lodge consent,
targeting CY2025
Consent
lodged
Status
Consent under
assessment
Potential
for BESS
1
co-location
(100MW
consented)
Upper North
Island generation
benefits GWAP
Ease of
Grid access
Strong fit
with portfolio
Most
advanced
wind project
Panel
Convened
13
Regulatory focus: Transition to Net Zero 2050
•Declining performance of NZ’s natural gas fields with
recent drilling campaigns underperforming expectations.
•Indigenous gas capacity and production flexibility limited.
•While the oil and gas exploration ban has been reversed,
short-term supply remains tight.
•Industry and government together investigating Liquified
Natural Gas (LNG) import options.
Fuel security
Contact’s focus on accelerating new renewable generation, flexible storage and customer-focused demand
response solutions aligns with the political and societal imperative for the market to deliver a secure, low
emissions, and renewable electricity market
Supporting the
evolution of the
market
Resource
management reform
•The continued expansion of renewable technology may
require some marketadjustments to ensure they are
integrated efficiently, and resulting volatility is manageable.
•Government has initiated reviews of both the market
settings and the regulatory framework to consider what (if
any) changes are necessary. Two reviews are underway:
•EA and ComCom Energy Competition Task Force
•Review of Electricity Market Performance, led by
Frontier Economics.
•Wide ranging resource management reforms underway,
including Fast Track Approvals Act, amendments to the
Resource Management Act (RMA), and work to
strengthen the National Policy Statement on Renewable
Energy Generation (NPS-REG).
•Will play a crucial role to meet infrastructure challenges
of decarbonising NZ economy.
ThemeContact Approach
Timing
•Contact transitioning from gas reliance and
investing in renewable flex e.g., batteries.
•Making Taranaki Combined Cycle gas plant
available for 2025 (if supported by the
market).
•Entered into heads of agreement to
investigate the potential for using Huntly to
manage dry year risk.
•Contact’s focus is on ensuring the regulatory
settings support our continued advancement
of the investment pipeline.
•Contact is engaging closely with government
reviews currently underway, including
providing expert input to support good
decision making.
•Contact will seek to utilise fast-track
consenting to enhance flexibility in the Clutha
scheme.
•Community engagement remains central to
Contact’s approach.
•Engaging with officials and Ministers on wider
RMA reforms for alignment with our
decarbonisation strategy.
•Bill to repeal oil and gas ban is
underway.
•Decisions regarding LNG import or
other fuel security options expected in
early 2025.
•Huntly dry year cover arrangement
could be in place for 2026.
•Task Force consulting on proposals
over 1H CY2025.
•Review of Electricity Market
Performance expected to be
completed by the end of June 2025.
•Fast Track Approvals Act was passed
into law at the end of 2024.
•Second RMA Amendment has been
introduced and is expected to be
passed into law by mid-2025.
•Work on NPS-REG ongoing.
14
Market
context
15
National electricity demand
Source: EMI, Contact.
*Does not include NZAS
National electricity demand (TWh)
Regional
change (%)
1H25 vs 1H24
Source: EMI, Contact. EMI demand data is grossed up to account for losses in distribution networks.
Market demand
2.6
2.6
2.5
2.5
2.5
2.5
1.9
5.0
5.3
5.4
5.2
5.5
5.6
5.7
13.4
13.5
13.4
13.3
13.2
13.3
13.3
1H191H201H211H221H231H24
0.6
1H25
NZAS demand response
North Island
South Island (ex NZAS)
NZAS
21.0
21.4
21.3
21.1
21.2
21.4
21.5
0.3%
0.4%
NZAS demand response was called on to support dry market conditions, contributing to a reduction in
national New Zealand electricity demand of ~2% on 1H24 (up ~0.4% normalised for NZAS)
Total national electricity demand
decreased by 0.5 TWh (2% from
1H24).
•Central North Island demand was
down 51% on the prior comparable
period on the back of operational
pauses and closures at the
Tangiwai / Karioi pulp and paper
mills in August.
•East Coast regional demand was
up 20% with Pan Pac’s Whirinaki
site reopening after temporary
closures last year as a result of
impacts from Cyclone Gabrielle.
•Normalising for NZAS demand
response (activated at the
beginning of the half year) demand
was up ~0.4%.
(3%)
(51%)
4%
3%
(3%)
(1%)
(4%)
10%*
4%
(1%)
(1%)
1%
(1%)
0%
2%
1%
4%
20%
1%
20.9
2%
16
Hydro generation was down 9.2%
on 1H24, as a result of historically
low inflow volumes at the beginning
of 1H25 and below average storage
volumes at the end of FY24.
Impacts included:
•
Volatile spot wholesale prices.
•
Need for thermal generation.
•
Higher industry carbon
emissions.
Diesel generation was significantly
higher than 1H24 as Whirinaki was
brought on in July / August
3
.
Geothermal generation volumes
increased materially in 1H25 with
Tauhara operational and Te Huka 3
entering commissioning during the
period.
Generation by type (TWh)
1
Hydro storage levels started 1H25 significantly lower than the historical mean following a very dry end to FY24. Storage
continued to be drawn down quickly as dry conditions persisted through July and into the beginning of August.
Conditions eased from August following several heavy rainfall events starting in late August and storage recovered
quickly before ending the period well above mean. This hydro storage and inflow variability lead to spot price volatility in
the first quarter and highlighted the market’s continued reliance on thermal generation to maintain supply.
Source: EMI & MBIE
Source: NZX – mean represents post-market mean storage volumes.
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
Dec-
22
Jun-
23
Dec-
23
Jun-
24
Dec-
24
Mean
Actual
1H25
1H24
Storage TWh
National hydro storage
Carbon emissions (mT)
1
Generation by type has been restated for prior periods due an adjustment in methodology.
2
Carbon emissions for 1H25 Oct-Dec quarter has been estimated using historic conversion rates with actual generation data.
3
Diesel generation volume (17.6GWh) is included in other generation figures.
Hydrology significantly impacted generation mix
Fuel supply
Hydro volatility highlights the role of thermal generation for security of supply; geothermal powers up
2H242H23
Carbon emissions remained elevated in 1H25 due to diesel and gas
generation in 1Q25.
0.1
1.3
1.8
2.1
3.7
3.7
4.4
14.1
12.6
11.4
0.2
1.3
0.8
1.3
1.5
1.8
0.5
1H23
0.5
1H24
0.4
1H25
Gas
Coal
Hydro
Geothermal
Wind
Solar
Other generation
21.2
21.4
20.9
1.01.8
1.8
2
17
Demand
Carbon
Short-term external factors that
can influence the market
Changes as at 31 December 2024
in comparison to 30 June 2024
Short-term
wholesale
electricity
prices
Spot gas prices were
volatile, from record
highs in August ending
the period down ~27%
after hydro storage
concerns abated.
5.
Methanol pricing at
US$344/t
(up 1%) but constrained
gas affecting domestic
production levels.
2
Demand down ~2%
year on year.
3
Thermal coal prices
lower
2
(US$129/t, down
~3%).
Forward wholesale pricing reflects gas cost and
increasing cost of new-build renewables
Hydro storage has been
volatile over the period.
Controlled storage
swung between ~43% of
mean (~1,278 GWh
below mean) in Aug 24
to ~115% of mean (~995
GWh above mean) in
November 2024.
Wholesale and futures electricity pricing ($/MWh)
Wholesale market
0
50
100
150
200
250
300
350
400
450
500
Dec-
14
Dec-
15
Dec-
16
Dec-
17
Dec-
18
Dec-
19
Dec-
20
Dec-
21
Dec-
22
Dec-
23
Dec-
24
Long-dated futures (>12 months)
Short-dated futures (<12 months)
Monthly average spot price
Source: EMI wholesale pricing
Carbon prices remained subdued (~$62 / NZ unit).
4
1
NZX hydro information;
2
Bloomberg;
3
EMI;
4
As at 20 December 2025;
5
Energy Market Services
Dry hydrology conditions at the end of FY24 and beginning of 1H25, and increasing scarcity and cost of gas, dramatically increased spot price volatility and pushed both the spot and
near-term futures prices to all time highs. These prices quickly reversed when dry conditions eased and the Methanex deals with Genesis and Contact were announced (average
monthly spot prices dropped 92% from their peak). However, long-dated futures have remained elevated reflecting market expectations of structurally higher gas prices and lower
availability and the increasing long-run costs of new-build renewables.
10 year
average
spot price
$116/MWh
5 year
average
spot price
$148/MWh
Gas outages and
availability decline
Reliable, plentiful
natural gas
18
•Competition remains intense despite sustained high wholesale futures prices.
Market churn continues to reflect this with residential switching at ~20%.
•New buildings contributed to a continued ~1.4% p.a. growth in total residential
ICPs on the prior year.
•Tier 1 retailers have a seen a 1% increase in market share to ~84% in
December 2024 (~83% December 2022).
•Tier 2 retailer growth rates have been mixed as they have repriced to rising
input costs (energy and networks), resulting in a collective decline in market
share to ~16% (~17% December 2022). Flick and 2Degrees continue to grow
strongly.
•Since 31 December 2022, 2Degrees has grown connections by 6k (+12.7%)
while Flick Electric has seen a 16k increase in connections (+64%)
•Contact electricity connections are up +22k from December 2022 to December
2024, resulting in a ~20% market share.
Change in customer electricity connections (000s)
31 December 2022 – 31 December 2024
2yr % change2yr ICP delta (1000s)
Retail electricity tariff changes
1
(c/ kWh)
Tier 2: -7.6k connections
•Increasing wholesale energy and, more recently, network costs have
resulted in a lift in residential electricity tariffs with the compound annual
growth rate of 3% across the last five years to November 2024.
•Average tariff increases for the year to November 2024 of 5% were above
consumer price inflation (~2.2%)
3
, with residential price increases rising to
cover both increasing lines costs and continue the partial recovery of energy
costs.
•Input cost pressure for retailers is expected to continue with ongoing
elevated wholesale prices and significant network cost increases starting
from 1 April 2025. Residential price increases are expected to remain above
the level of inflation to recover these rising input costs.
12 months
ended:
Tier 1: +74k connections
Source: MBIE
7%
6%
3%
-9%
-6%
-25%
13%
8%
-20
-10
0
10
20
30
70
-30
GenesisContact
2%
MercuryMeridianNovaPulse
64%
FlickElectric Kiwi2Degrees/
Vocus
Other
18.1
19.4
20.1
20.9
21.8
22.6
12.1
11.1
11.3
11.6
11.9
12.7
Nov-19Nov-20Nov-21Nov-22Nov-23Nov-24
30.2
30.5
31.5
32.5
33.7
35.4
+3%
2
Differences in retail strategies apparent
Retail electricity market
Electricity and lines costs continue to rise; pass-through cost increases to continue
Lines (c/kWh)Energy & Other (c/kWh)
1
Inclusive of GST
2
Compound annual growth rate
3
Stats NZ CPI index increase in the 12 months to December 2024.
Source: EMI
19
Financial
results and
outlook
20
Key themes from the financial results
Facilitated Methanex gas supply
arrangement (~3.5PJ) to support
the market through winter 2024
Improved plant availability for winter
2025 and secured long-term gas to
support security of supply
New long-term NZAS contract commenced
1 July 2024 on improved pricing –
demand response immediately activated
Two new geothermal plants online,
Tauhara and Te Huka 3, delivering
0.6TWh
Announced Manawa Scheme of
Arrangement – now preparing for
combination with Manawa
1
1
The transaction (and proposed combination with Manawa) remains subject to conditions, including NZ Commerce Commission clearance, approval of the Scheme by the High Court and by Manawa shareholders by the requisite majorities. See slide 35.
21
Profit ($m)
EBITDAF up $70m (21%) on 1H24 underlying, reflecting an increase in renewable generation from Tauhara and
Te Huka 3 during the period, the net impact of gas-backed CFDs and long-term contracts commencing
Profit of $142m for 1H25
EBITDAF ($m)
Gas and acquired
generation costs
were impacted by the
cost of Methanex
gas and NZAS
demand response.
Reflects net
impact of new
repriced NZAS
contract and
Tauhara-linked
PPAs coming
online.
Renewables up
527GWh
including
491GWh uplift in
geothermal
volumes.
Other income
reflects loss on
sale of excess
gas (-$18m).
43
1
1H25 results
Net interest
costs
EBITDAFDepreciation
& Amortisation
Tax
1H24
EBITDAF
1
1. Renewables
1H25 EBITDAF
2. Net Volume
2
Location losses
were elevated as
a result of low
wholesale prices
in 2Q25 following
significant hydro
inflows.
1H25 profit
Profit - incl AGS net provision release post-tax
Underlying profit
134
142
70
-4
-32
-26
1
153
Higher contracted
sales volumes
partially offset by
NZAS demand
response.
6
Note: All 1H24 figures are exclusive of the impacts of the onerous contract provision for AGS. Impacts of the onerous contract in 1H24 are as follows, EBITDAF (+$29m), interest (-$3m), tax (-$7m), NOPAT (+$19m). The provision has not been
recalculated in 1H25, however, the monthly unwind and interest impacts of the provision are included in the reported 1H25 figures as follows, EBITDAF (+$7m), interest (-$2m), tax (-$1m), NOPAT (+$4m).
3. Long Term
Chanel Pricing
5. Gas, carbon
and acquired
generation price
6.Location
losses
7.Other income
334
404
114
28
55
7
-83
-18
-16
-13
362
25
4. Market Channel
Pricing
Higher realised
CFD prices from
sales linked to
Methanex gas.
5
8
7
1H24 profitFV of financial
instruments
8.Fixed
operating costs
Fixed costs higher
due to inflation
impacts, growth
and one-off costs
associated with the
proposed Manawa
acquisition ($10m).
EBITDAF - incl AGS net provision release pre-tax
Underlying EBITDAF
22
Wholesale EBITDAF
1
($m)
Retail EBITDAF ($m)
Corporate / unallocated costs ($m)
Business performance by segment
EBITDAF up by $70m on underlying 1H24
Refer to slides 23 - 25
Refer to slide 26
358
466
53
168
1H24Generation
costs
(including
acquired
generation)
Total
contracted
revenue
6
Trading,
merchant
revenue
and losses
1H25
+109
-1
-25
1H24
0
Electricity
Volumes
22
46
Electricity
Prices
2
Other
products
2
1
Opex1H25
-24
Electricity gross margin
(-$23m)
Electricity
and network
cost inflation
Price recovery
2
Other products includes retail gas and telco gross margins and other
revenue/costs.
1H25 results: Segmental performance
-23
-37
1H24
10
Transaction
and Integration
preparation
costs
3
Inflation &
Performance
1H25
-14
1
Simply and Western included within Wholesale EBITDAF.
1H24 EBITDAF is shown as underlying, excluding $29m net release of the onerous
contract provision for AGS. 1HY25 EBITDAF includes monthly unwind of +$7m.
23
Electricity generated or acquired (GWh)
Costs up $53m driven by higher cost of thermal fuel and acquired generation plus Tauhara online
1H25
1H24
Electricity generated or acquired costs ($m)
Generation costs
1H25 results: Wholesale business
Gas and diesel
Acquired
Thermal
Renewable
Gas storage
Carbon costs
Electricity and gas
transmission and levies
Other operating costs
Generation volumes
•
Hydro generation of 1,952GWh was up on 1H24 (2%) owing to high
inflows in the second quarter of 1H25.
•
Geothermal generation was up 491GWh (30%) on 1H24, from Tauhara
generation (584GWh) and Te Huka U3 generation during commissioning
in December (40GWh). Additional volumes were partially offset by a
planned outage at Te Mihi.
•
Despite a dry start to the period, 1H25 thermal generation volumes were
down 309GWh down (-38%) on 1H24. This is in part because;
•
1H24 saw significant use of thermal to cover a delay to Tauhara’s
online date alongside some must-run winter 2024 gas contracts, and
•
The second quarter of 1H25 saw significant inflows which, when
combined with new geothermal generation, offset thermal generation.
Costs
•
Renewable generation costs were up $12m (19%) as a result of higher
geothermal carbon and operational costs associated with Tauhara.
•
Thermal generation costs in 1H25 benefited from an unwind of the AGS
provision (+$7m). This was partially offset by higher thermal fuel and
carbon costs (-$5m).
•
Thermal fuel costs increased to $166.80/MWh (1H24: $96.40/MWh) due to
a higher cost of gas (1H24: $8.3/GJ, 1H25: $15.2/GJ), higher utilisation of
Whirinaki (1H24: 0GWh, 1H25:18GWh) and a higher unit price of carbon
(1H24 $59/unit, 1H25 $74/unit).
•
Acquired generation costs were significantly higher in 1H25 ($43m up on
1H24) as purchases were made ahead of winter 2025 and due to NZAS
demand response payments. In comparison, in 1H24 gas was more
readily available and Contact was able to use this to deliver similar cover.
1,652
2,143
1,916
1,952
817
508
239
246
1H241H25
Acquired
Thermal
Hydro
Geothermal
4,624
4,849
58
66
63
17
75
18
108
56
106
61
30
29
73
33
13
30
73
3
4
7
205
205
258258
+53
81%
Renewable % of
own generation
89%
$52.5/MWh
$43.5/MWh
Development
Acquired generation
costs
All 1H24 analysis in this section is presented on an underlying basis. As such,
1H24 gas storage costs exclude the $29m net release within EBITDAF of the
onerous contract provision for AGS. 1H25 gas storage costs include an AGS
provision unwind benefit (+$7m positive impact).
24
1,991GWh
$152.6/MWh
Contracted
revenue ($m)
The Methanex gas deal at the beginning of 1H25 was backed by an electricity supply agreement with
Meridian leading to a significant increase in CFD sales volumes
1,423GWh
$218.2/MWh
+3GWh
+$12.0MWh
+154GWh
+$78.5/MWh
•Fixed price variable volume electricity sales to the Retail segment and C&I customers
ended 75GWh higher than 1H24 (+$34.2m). The volume shift is attributed to C&I as Retail
volumes held largely steady.
•Pricing to C&I was broadly in line with last year given short term channels
(including CFDs) were prioritised over C&I re-contracting in response to
uncertainty of gas supply contracts, geothermal plant commissioning and prior
swaption supply contracts.
•Transfer price to the Retail channel was up $12/MWh to $152.6/MWh reflecting
higher wholesale prices over the three preceding years.
•Strategic fixed price sales were 74GWh lower than 1H24 but average pricing across the
channel was up significantly resulting in a $14m uplift in revenue. This movement in pricing
and volume reflects:
•Pricing: The signing of the long term deal with NZAS (in 2H24 – beginning 1H25)
was at a higher price than the prior contract.
•Volumes: Lower volumes reflect the implementation of demand response by NZAS
at the beginning of the period in response to dry conditions.
•CFD sales volumes were up by 154GWh as a result of Tauhara being online for the whole
period and a significant risk management contract sold to Meridian at the beginning of
1H25. Prices were up by $78.5/MWh reflecting the market conditions at the end of FY24
and the beginning of 1H25.
•Steam sales were steady in both volume and revenue compared to 1H24.
•Other income was significantly lower (-$14.6m) primarily as a result of losses on sale of gas
that could not be stored or economically used for generation in the period.
Wholesale contracted revenue
24
615GWh
$135.3/MWh
+72GWh
+$0/MWh
280
304
73
83
177
311
30
44
4
2
-6
1H24
-12
2
-5
1H25
Other net income
Steam sales
Strategic fixed price sales
CFD sales
C&I net price
Retail segment sales
C&I channel
and decarbonisation
support costs
559
728
+168
1H25 results: Wholesale business
528GWh
$82.5/MWh
-74GWh
+33.3/MWh
Year-on-year
changes to
volume and
price
1H25
volumes and
price
25
Trading EBITDAF ($m)Long / short position (GWh)
$181.6/MWh
5.8%
($10.4 / MWh)
5.1%
($6.7/ MWh)
Merchant generation revenue in 1H25 was
characterised by two distinct periods –
•In Q1 Contact was broadly neutral on
merchant sales volumes in a much higher
priced spot market (much of our potential
merchant revenue in this period was
converted toshort dated CFD's). Higher
prices in Q1 meant Contact’s LWAP /
GWAP costs were largely covered.
•In Q2 the significant rainfall saw periods
of spill in Contact's hydro dams, reducing
hydro length and causing some
LWAP/GWAP losses (at very low
spot prices). The net result was that
LWAP / GWAP losses outstripped
merchant revenue over the quarter. This
volatility also saw location risk
management products (FTRs) out of the
money.
During 1H25 an accrual adjustment was
made in relation to final settled electricity
prices during the August 2021 UTS resulting
in a $1.6m expense relating to accruals from
FY22.
Trading revenue
Merchant sales: short-term sales channel available when the
spot prices exceed the opportunity cost of Contact generation.
LWAP / GWAP losses: locational price differences
between where electricity is generated and purchased.
Wholesale trading and merchant revenue
$131.9/MWh
Spot purchases and sell
CFD settlement
Spot sales and buy CFD
settlement
Merchant generation
29
42
-29
-48
1H241H25
0
-6
223
231
4,402
-4,402
1H24
4,618
-4,618
1H25
1H25 results: Wholesale business
LWAP/
GWAP
losses
Merchant
sales
$/MWh
26
1
Retail business performance
EBITDAF ($m)
Margins contract as wholesale electricity and lines costs rise faster than tariff; Contact gaining connections via time
of use and multi-product offerings
Revenue & Tariff
1
($m)
1H241H25Variance
$m$mTariff¹$mTariff
Electricity revenue
5245442922012
Gas revenue
51524316
Telco revenue
3948719(1)
Other income
44-
Total revenue
61864830
Contract Asset (closing)
451
# of connections (closing)
2
591k630k
Cost to serve/connection
3
$63$57
1
Tariff is $/MWh for electricity, $/GJ for gas and $ per month per customer connection for Telco.
2
Retail connections only, excludes Simply Energy.
3
Reflects total operating costs (direct and indirect) / average connections.
5
6
19
7
10
-4
-37
-36
2
1H24
2
1H25
-1
-25
Gross Margin (GM) is Revenue less Cost of Goods
(Networks, meters, levies, energy, carbon and telco)
4
Input costs shown per MWh at the GXP.
1H25 results: Retail business
Other
Gas GM
Electricity GM
Telco GM
Other operating
expenses
Retail margins have contracted, driven by sustained high wholesale
electricity prices and rising lines costs.
•Retail EBITDAF decreased by $24m on 1H24 largely driven by the
$46m increase in electricity input costs that were not fully passed
through to customers.
Contact’s average retail electricity tariff increased by 4.3% reflecting
retail price rises to partially offset rising wholesale and lines cost
increases.
•Around 90% of customers received a price increase in the last 12
months.
As the energy industry decarbonises, cost pressure for retailers is
expected to remain, including:
•Significant investment in lines infrastructure.
5
•Elevated wholesale futures prices over the medium term.
This will result in an increase in the cost that consumers will pay over
the coming years.
Connections grew strongly since 2H24 particularly through telco and
Time of Use (ToU) electricity ‘Good’ plans, with a focus on multi-
product customers.
•Total connections +39k on 1H24 with telco up 23k and energy
up 16k.
•Multi-product customers up 12% on 1H24, driven by telco products
(including successful launch of new mobile product option)
alongside ToU ‘Good’ plans growth.
Cost to serve – reduced by $6/connection, largely driven by timing of
the marketing spend and productivity improvements through continued
growth in digitised interactions, partially offset by wage inflation.
70k
93k
428k
1H24
73k
116k
442k
1H25
Gas
Telco
Electricity
591k
630k
Closing connections (k)
2
5
The Commerce Commission indicated that the transmission and distribution component
of a household’s electricity bill will increase on average, by $10 to $20 per month from
1 April 2025, for affected networks (varies across regions and customer profiles).
Electricity
transfer price
4
$141/MWh$153/MWh
Networks,
meters and
levies
4
$113/MWh$122/MWh
27
Other operating
cost movement
($m)
Base
movement
Non-recurring & performance
•$2m costs related to movement in performance-based accrued costs in line
with year-to-date performance.
•$1m nonrecurring costs relate to Wairakei extension feasibility.
Base movement
•$6m general inflation of 2-4% impacting operating costs. These have been
seen across the business, including labour cost and local body rates.
•$1m headwinds related to premium increases for staff health insurance
programmes and extra staffing required to support Retail call centres during a
period of higher than normal price change activity.
•-$4m timing movements largely driven by timing of Retail marketing and other
activity.
•-$1m insurance savings from change in insurance programme provider.
Growth and sustainability
•$3m incremental costs with Tauhara online.
•$1m incremental investment related to retail connection growth.
•$1m increase in development projects which are in feasibility phase.
Manawa related costs
•$10m of transaction and integration related costs incurred. Made up of $8.6m
of transaction related costs and $1.6m of integration planning activity.
Operating costs increase on inflation and growth
Timing related movements
General cost inflation
Invest in
growth and
sustainability
1H25 results: Operating costs
Headwinds
3
5
10
4
6
1H24Non-recurring
& Performance
1
1
Base movementGrowth &
Sustainability
Underlying OpexManawa
Related Costs
1H25
Reported
123
2
133
143
Non-
recurring &
performance
Manawa
Related
Costs
Note:1H24 Opex is adjusted from that presented in the 1H24 results presentation due to an accounting treatment change relating to asset write-offs and impairments.
Insurance savings
28
•Higher underlying EBITDAF on greater alignment of channel prices to the wholesale market.
•Working capital changes were $70m greater than in the prior year due to higher value and levels of
stored gas following the purchase of gas from Methanex.
•Interest paid, net of capitalised interest, was $34m higher than 1H24, with the completion of Tauhara
reducing the interest capitalised to the project.
•1H25 stay-in-business (SIB) capital expenditure includes completion of the Peaker refurbishment
and Te Mihi spare rotor acceleration projects. Te Mihi Stage 2 pre-FID costs have been reclassified
as SIB capex in 1H25 ($2m) and 1H24 ($22m). These were previously allocated to growth capex.
•Non-cash items included within EBITDAF in 1H25 include the AGS onerous provision unwind (+7m).
6 months ended
31 December 2024
(1H25)
6 months ended
31 December 2023
(1H24)
Comparison
against 1H24
EBITDAF
1
$404m$334m↑$70m
Working capital changes($80m)($10m)↑$70m
Tax paid($74m)($66m)↑$8m
Interest paid, net of interest capitalised($43m)($9m)↑$34m
SIB capital expenditure($65m)($85m)↓$20m
Non-cash items included in EBITDAF($4m)$10m↓$14m
Operating free cash flow$138m$174m↓$36m
Operating free cash flow per share17.4 c22.1c↓4.7 c
Cash conversion (OpFCF / EBITDAF)34%52%↓18%
Cash conversion for 1H25 impacted by higher EBITDAF, higher fuel inventory and higher interest payments
Cash flow and capital expenditure
Sources and uses of cash ($m)
1H25: Cash flow
138
179
67
4
13
161
Sources
2
181
Uses
379
379
14
Cash Movement
Debt drawdown
OpFCF
DRP
Capital calls for investments in associates
Growth investment
Dividends paid
Realised losses on market derivatives
Financing cost / cost of debt issuance
1
1H24 EBITDAF is shown as underlying, excluding $29m net release of the onerous contract provision for AGS. 1HY25 EBITDAF includes monthly unwind of +$7m.
29
Growth capital expenditure
1H25 results: Growth capital expenditure
Growth capital expenditure in 1H25 reflects Contact’s continued commitment to renewable development
•The Tauhara geothermal station has been generating since May 2024. Final commissioning activity was
completed in 1H25. Construction of Te Huka 3 is substantially complete and final commissioning activity
is underway.
•Investment in Te Mihi Stage 2 was confirmed in November 2024. The Wairakei extension project is
classified as stay-in-business capex and is illustrated on slide 36 (excluded from this slide).
•Construction is underway on a 100MW grid-scale battery (BESS) at Glenbrook, with $42m spent as at
31 December 2024. The BESS is expected to be completed in FY26 with remaining growth capex falling
across both 2H25 and FY26.
•Remaining spend on wind projects reflects current pre-FID approval levels and will be updated after final
investment decisions, as applicable.
•For major growth projects Contact capitalises interest from the time of final investment decision (FID) or
significant pre-FID works through to commissioning, on a rate that reflects the average portfolio interest
rate.
•Investment in Kōwhai Park solar was confirmed in August 2024. Contact’s investment will not be
captured within growth capex, rather it will be recognised within investment in joint ventures and
associates.
Growth capital expenditure – cash basis ($m)
1
Up to
30 June 2024
6 months ended
31 Dec 2024
Remaining under
current
approvals
Total
2
Tauhara$852m$46m$26m$924m
Te Huka 3$246m$24m$30m$300m
Te Mihi Stage 2
3
$57m$47m$608m$712m
Wind$13m$4m$3m$20m
Glenbrook battery$5m$37m$121m$163m
Capitalised
interest
$173m$10m$63m
4
$246m
Total$1,346m$168m$851m$2,365m
1
Excludes $11m associated with Western Energy coil tube drilling and deployment of demand flex technology.
2
Total under current Board approvals.
3
Growth capital expenditure for Te Mihi Stage 2 (previously GeoFuture) has been restated following the project reaching FID in November 2024. A portion of capital spent up to June 2024 ($41m) was reclassified to stay in business capex as it
related to spend on both existing plant within the Wairakei field and the extension of Wairakei power station. Stay in Business capital spent for the Wairakei extension in 1H25, and expected capital spend to the end of FY25, is broken down
further on slide 36.
4
Relates to Te Huka 3 geothermal development (FY25 only) , Te Mihi Stage 2, and Glenbrook battery development (life of project).
30
•Gross debt has increased in line with the continued build
out of the capital investment programme. This is
expected to continue to grow as projects are
constructed.
•A $100m Retail Bond matured in August 2024 and was
replaced with a $250m Capital Bond in October 2024.
The hybrid structure of the new bond provides an equity
credit for Contact’s S&P rating (50%), reducing S&P net
debt for the Net Debt / EBITDAF calculation.
•Contact targets a BBB investment grade credit rating
with S&P. This requires net debt to EBITDAF to remain
below 3.0x over a sustained period. Point estimate net
debt to EBITDAF is currently 2.3x at the half year.
Contact’s EBITDAF outlook, DRP and capacity for
further hybrid bonds allow this metric to be managed
effectively.
•Contact continues to be at the forefront of sustainable
finance and has extended its $850m sustainably-linked
loan
3
. This loan has KPIs with financing incentives or
penalties relating to emissions reductions, renewable
energy development and performance in the Dow Jones
Sustainability Index (DJSI).
Supporting Contact’s growth with diverse sources of funding with strong green credentials
Closing net debt ($m)
Face value of borrowings less cash
Interest rate (%)
Weighted average gross interest
1
on average borrowings
Net debt to EBITDAF (x)
Includes S&P adjustments (prior to FY20, AGS was treated as a lease)
2
Borrowing maturities ($m)
Average tenor of 8.3 years as at 31 December 2024
Strong balance sheet
1
Gross interest includes all interest on borrowings, bank commitment fees and deferred financing costs. Unwind of leases, provisions and capitalised interest not included.
2
Illustrated here on a point basis based on expected S&P adjustments. FY25 is based on a normalised EBITDAF of $770m.
3
Term extended by 12 months.
990
1,036
774
1,025
1,474
1,834
2,000
-229
-216
25
-47
FY19
22
-44
FY20
21
-150
FY21
25
-168
FY22
49
-140
FY23
47
FY24
50
HY25
968
1,014
645
882
1,383
1,652
1,834
Lease obligationsBorrowingsCash on hand
4
67
434
225
250
135
350
300
150
250
350
FY25
7
FY26
7
FY27
22
4
FY28FY29FY30FY31FY52FY55
292
357
625
367
Undrawn bank facilities
Domestic bonds
USPP
NEXI
Capital bonds
AMTN
2.3
2.4
1.4
1.8
2.6
2.7
2.3
FY19FY20FY21FY22FY23FY24HY25
1,224
1,029
974
892
1,310
1,727
1,920
5.4%
FY19
5.2%
FY20
5.2%
FY21
5.3%
FY22
5.8%
FY23
6.1%
FY24
6.0%
HY25
Average gross interestAverage gross debt
1H25 results: Key balance sheet metrics
31
Ordinary dividends ($m)
Declared
Final dividendInterim dividend
% pay-out of operating free cash flow
Dividend for 1H25
165
163163
164
182
128
115
109109
109
110
FY20FY21FY22FY23FY241H25
280
272272
273
292
128
cps
Interim dividend for 1H25 of 16 cents per share
•Interim dividend of 16 cents per share is imputed to 88% or 14 cents per share for qualifying shareholders.
•Record date of 25 February 2025; payment date of 18 March 2025.
•The NZD/AUD exchange rate used for the payment of Australian dollar dividends will be set on 6 March
2025.
Dividend reinvestment plan (DRP)
•Shareholders will have the option of full, partial or no participation. If a shareholder elects to participate,
they will remain in the plan at the same participation level until they elect to terminate or amend their
participation level.
•A 2% discount will be offered for the FY25 interim dividend and Contact will have the right to terminate or
suspend the plan at any time.
•Dividend reinvestment plan application forms must be in by 26 February 2025 to confirm participation in
the plan.
•Trading period for setting the price for the DRP is 24 February 2025 to 28 February 2025. DRP strike
price will be announced: 6 March 2025.
97%72%
82%97%
39
35
35
37
35
62%93%
16
Uplift of 2 cents per share on 1H24, in line with 39 cents per share guidance for FY25
32
Normalised and expected FY26 EBITDAF
Assumes mean hydrology conditions
Strategic fixed price2,400GWh$85/MWh$204m
CFDs1,100GWh$145/MWh$160m
C&I1,450GWh$160/MWh$232m
Retail3,800GWh$160/MWh$608m
Other income³$50m
$1,254m
Hydro mean3,940GWh$0/MWh-$0m
Geothermal average4,970GWh$4/MWh-$20m
Thermal250GWh$200/MWh⁴-$50m
Acquired100GWh$300/MWh-$30m
-$100m
Length⁵$102mTransmission/Storage-$65m
Location losses⁶-$101mOperating expenses-$280m
Total$1mTotal-$345m
1.All volumes are at the Grid Exit Point (GXP)
2.Net price is equal to tariff less pass-through costs (network, meters and levies) /MWh
ASSUMPTIONS FOR NORMALISED EARNINGS
3.Steam sales, retail gas gross margin, telco gross margin and other income
4.Gas price of $15.0/GJ, carbon price of $76/unit and thermal portfolio heat rate (10.5GJ/MWh)
5.Length of 510GWh p.a. assumed
6.Locational losses of 5.8% on spot purchases and settlement of
CFDs sold at a wholesale price of $145/MWh
* Fuel is natural gas and carbon costs.
** Retail volume contracted. Competitive risk remains on pricing achieved.
820
280
Channel choices maximise
long term value¹
1
Net price² driven by
best commercial practices
2
x
=
FY assumptions that deliver expected & normalised EBITDAF for FY26
Fuel cost
Net Revenue
Trading
Fixed costs
Hydrology & Asset
availability optimise generation
3
4
Total
x
=
Access to and price of fuel* drives
financials & risk position
Total
Trading delivers value to more
than offset locational losses
5
Digitalisation & continuous
improvement optimise fixed costs
6
x
x
x
x
x
x
x
=
=
=
=
=
=
=
903
547
3,800
2,400
CFDs
C&I
Retail
Strategic fixed
$145/
MWh
$160/
MWh
$160/
MWh**
ContractedUncontracted
1,254
-100
-345
1
810
x
372
348
290
149
176
263
318
268
127
143
227
Jul-25Sep-25Nov-25Jan-26Mar-26May-26Jul-26
ASX Futures $/MWh
At 14 Feb 2025
$85/
MWh
OTA monthly
OTA Quarterly
BEN Monthly
BEN Quarterly
Note, all figures are subject to rounding.
=
353
33
Questions
34
Supporting
materials
35
Preparing for Contact’s combination with Manawa
Key eventIndicative date
Entry in Scheme Implementation Agreement11 September 2024
NZ Commerce Commission (NZCC) application registered30 September 2024
Receipt of initial Court orders13 February 2025
NZCC decision31 March 2025 (current schedule)
Issuance of Scheme Booklet to Manawa shareholdersAs soon as practicable following NZCC approval
Manawa Scheme MeetingFour weeks post issuance of Scheme Booklet
Second Court hearingApproximately two weeks post Scheme Meeting
Target for implementation of the SchemeEnd of first half CY2025
Indicative transaction timeline
2
1
For a full description of transaction rationale and benefits, see Contact’s announcement and presentation released on the NZX on 11
th
September 2024, linked here
2
All dates are indicative only and subject to change. The dates assume there are no delays or complications, including with respect to court and regulatory approvals, and will depend on the timing of each other step and satisfaction
of the conditions precedent.
•Statement of Issues (SoI) released on
5
th
February 2025 with submissions due by 21
st
February 2025.
•Contact and Manawa have each provided
substantive supporting evidence to the NZCC as
part of its ongoing assessment process and will
continue to assist the NZCC in its understanding
of the matters noted in the SoI.
•On 11
th
September 2024, Contact entered into a Scheme Implementation Agreement (SIA) to acquire 100%
of Manawa via a mixture of Contact shares and cash.
•The proposed combination is expected to create a more diversified, resilient and efficient Contact business,
which will be positioned to better manage dry year risk, execute on renewable development opportunities and
support New Zealand’s energy transition.
1
•The transaction is subject to various conditions, each as set out in detail in the SIA, including NZ Commerce
Commission (NZCC) clearance, approval of the Scheme by the High Court and by Manawa shareholders by
the requisite majorities.
•Contact is preparing for the combination with Manawa to ensure that the strategic, financial and energy
transition benefits are fully delivered.
‒Integration Director appointed and Integration Management Office established October 2024.
NZ Commerce Commission update
Targeting completion around the end of the first half of 2025
36
Guidance confirmation
Updated
FY25 guidance
1H25 resultChange to prior guidance
Stay in Business Capex
$120m - $130m$65m+$4 - 5m
Stay in business accelerated programme (cash)
~$40m$25m-
Stay in business capital expenditure (cash) BAU
$77m - $87m
$40m+$2mOhaaki statutory outage brought forward into FY25.
Stay in business capital expenditure (cash) Wairakei
$2m - $3m$1m+$2 - 3m
Wairakei extension costs reclassified from growth capex ($1m) and project costs
brought forward.
Growth capital expenditure (cash)
1
$450m - $550m$179m-
Depreciation and amortisation
$275m - $285m$130m-
Net interest (accounting)
$105m - $115m$52m
-$10mReduction in interest rates from initial guidance setting.
Cash interest (in operating cash flow)
$85m - $95m$43m
Cash taxation
$105m
-
$115m
$74m-$5m
Reduction in final FY24 tax cash payment due to utilisation of prior period tax
credits
Realised (gains) / losses on market derivatives not in a
hedge relationship
$15m - $20m$14m+$5m
Higher 1H25 result due to volatility in the market August/September 2024
(realised).
Corporate costs (ex Manawa)
$54m$27m+$2mMovement in performance-based costs in line with YTD performance.
Corporate costs (Manawa transaction and integration)
$20m$10mn/aExcludes costs linked to a successful transaction completion outcome.
Target ordinary dividend per share
39 cps16cps -In line with target payout of 39 cps – Interim dividend 41% of the expected total.
1
Growth capital expenditure includes capitalised interest and is based on current Board-approved capital spend.
37
Strategic fixed price700GWh$80/MWh$56m
CFDs885GWh$154/MWh$136m
C&I650GWh$150/MWh$98m
Retail2,050GWh$154/MWh$315m
Other income³$24m
$629m
Hydro2,030GWh$0/MWh-$0m
Geothermal2,100GWh$4/MWh-$8m
Thermal⁴130GWh$200/MWh-$26m
Acquired175GWh$215/MWh-$38m
-$72m
Length⁵$42mTransmission/Storage-$36m
Location losses⁶-$42mOperating expenses-$136m
Total$0mTotal-$172m
1H25 assumptions that deliver expected & normalised EBITDAF of $770m over a financial year
EBITDAF reconciliation to 1H25 ($m)
Hydrology & Asset
availability optimise generation
3
4
Total
x
=
Access to and price of fuel* drives
financials & risk position
Channel choices maximise
long term value¹
1
Net price² driven by
best commercial practices
2
Total
x
=
Trading delivers value to more
than offset locational losses
5
Digitalisation & continuous
improvement optimise fixed costs
6
x
x
x
x
x
x
x
=
=
=
=
=
=
=
* Fuel is natural gas and carbon costs
1.All volumes are at the Grid Exit Point (GXP)
2.Net price is equal to tariff less pass-through costs (network,
meters and levies) /MWh
3.Steam sales, retail gas gross margin, broadband gross margin and other income
4.Gas price of $8.2GJ, carbon price of $80/unit and thermal portfolio heat rate (10GJ/MWh)
5.Length of 223GWh for 1H25 assumed
6.Locational losses of 5.4% on spot purchases and settlement of CFDs sold
at a wholesale price of $155/MWh
6
5
65
32
14
14
10
2
385
404
Normalised and expected EBITDAF assumptions
1H25 results
With reconciliation to actual performance
x
Higher market channel price
Normalised & Expected
Lower renewables
Other income
Reported
Renewable generation below mean (-35GWh)
at expected thermal SRMC
Fixed costs
Driven by AGS provision unwind (+$7m non-cash)
and LCE rebates
Losses from sale of excess gas (-$18m) partly offset
by income associated with hedge products
Increased long-term channel price
Strategic fixed price sales price of $83/MWh in 1H25 higher
than full year expectation
CFD net price of $218/MWh in 1H25 higher than full year
expectation due to CFD sales backed by Methanex gas
Gas, carbon, acquired generation price
Uplift driven by Methanex gas and NZAS demand response
Higher sales volumes were offset by increased cost of acquired
generation and SRMC of thermal generation
Net volume impact
Manawa related costs
Transaction and integration preparation costs associated with the
proposed Manawa acquisition (-$10m)
=
414
EBITDAF pre-Manawa related costs
38
Contact generation output sold to the national grid (GWh)
Generation and sales position
1,652
1,649
1,524
1,659
1,605
1,652
2,143
2,045
1,886
1,984
2,391
2,053
1,916
1,952
836
825
870
360
817
508
1H191H201H211H22
246
1H231H241H25
Thermal
generation
Hydro
generation
Geothermal
generation
4,533
4,359
4,378
4,411
3,905
4,386
4,603
Operational data
Renewable % of
own generation
sold to grid
82%81%80%92%94%81%
Geothermal generation (GWh)
Geothermal generation was up 491GWh (30%) on 1H24, the uplift is attributable to Tauhara being online for the period and Te
Huka 3 entering commissioning and providing power to the grid in December. Partially offset by the planned Te Mihi outage.
716
709
559
692
690
715
578
486
493
567
531
489
518
534
203
181
168
154
161
155
171
165
170
165
159
154
584
92
1H19
95
1H20
104
129
1H21
99
1H22
107
1H23
99
1H24
40
113
139
1H25
1,652
1,649
1,524
1,659
1,605
1,652
2,143
Hydro generation (GWh)
Highly concentrated inflows in the second quarter of 1H25, after a very dry end to 2H24, saw Hawea storage
volumes increase significantly over the period. However, the highly correlated nature of the inflows also led to
high levels of spill.
415
244
375
339
374
1,872
2,178
2,013
2,123
2,675
1,855
2,339
-73
-707
-107
-960
-181
-761
246
1H191H20
-274
1H211H221H23
242
1H241H25
2,045
1,886
1,984
2,391
2,053
1,916
1,952
Inflows stored include uncontrolled storage lakes
Inflows
Inflows
stored
Spill
Thermal generation (GWh)
649
593
620
168
161
646
393
69
119
130
87
171
97
114
111
117
104
67
18
4
51
1H19
1
50
1H20
3
48
1H21
2
47
1H22
2
45
17
1H23
0
00
1H24
0
1H25
887
875
918
407
291
817
508
Te Rapa
Spot
Whirinaki
Te Rapa
Direct
Peakers
TCC
1H25 thermal generation volumes were 309GWh (38%) lower than 1H24 due to the following:
•Additional thermal generation was required to meet an increased sales position in light of the delay to
Tauhara online in 1H24; and
•Significant hydro inflows in the second quarter of 1H25, in conjunction with new geothermal output,
reduced reliance on thermal generation.
89%
Te Huka 3
Tauhara
Te Huka
Ohaaki
Poihipi
Wairakei
Te Mihi
39
Plant and fuel performance
Geothermal fuel extracted at Wairakei vs consented (mT)
Wairakei, Poihipi and Te Mihi conversion effectiveness
(MWh per kT extracted)
% of geothermal fluid extractedWairakei mass extracted
10
20
30
40
50
0
97%
44
1H19
100%
45
1H20
95%
43
1H21
100%
1H22
96%
43
1H23
100%
46
1H24
91%
42
1H25
45
-17%
32.3
30.7
30.3
31.4
29.8
30.3
29.7
1H191H201H211H221H231H241H25
-2%
Geothermal fuel performance
Taranaki combined cycle (TCC)
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
1H2137796%37%62012779
1H22377100%10%16818331
1H2337789%10%16110717
1H2437769%39%64612782
1H25377100%23%393418164
Hydro
Geothermal
Stratford Peakers
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
1H2178485%57%1,984110218
1H2278483%69%2,39190215
1H2378487%59%2,05352107
1H2478493%55%1,916123235
1H2578492%57%1,952129252
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
1H2142586%81%1,524118180
1H22410
1
96%92%1,659105175
1H2341094%89%1,6055689
1H24
41095%91%1,652134221
1H25
58490%80%2,143167357
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
1H21
202
86%14%13015120
1H22
202
74%10%8721619
1H23
202
57%2%171903
1H24
202
56%19%17115226
1H25
202
60%11%9712312
Plant availability
Availability Factor calculation includes all station outages (Planned, Maintenance, Forced) but does not consider plant deratings.
1
Reduction in geothermal net capacity is a result of decommissioning of wells on the Wairakei steam field.
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
1H21
158
91%0%33050.8
1H22
158
98%0%27831.8
1H23
158
97%0%22740.4
1H24
158
100%0%000.0
1H25
158
95%3%1866712
Whirinaki
Wairakei total mass extracted, and extracted volumes as a % of
consented mass take, was significantly down on 1H24 as a result of a
planned outage (25 days) at Te Mihi between September and October.
2
Statutory turnarounds occur after the first operating year of a new plant, again in operating year 3, and every four years
thereafter. The table shows which plant have a major statutory turnaround in the next 3 calendar years. The GWh impact is
an estimate based on understood scope at the time of publishing. Turnarounds in FY27 and 28 are indicative.
Upcoming geothermal statutory turnarounds (outages)
2
Plant Impact (GWh)FYFrequency & type
Te Mihi 90254y Stat turnaround
Te Huka 1&28254y Stat turnaround
Te Huka 32825One-off commissioning outage
Ohaaki 28254y Stat turnaround
Tauhara 11826Y1 Stat turnaround
Te Huka 33226Y1 Stat turnaround
Wairakei25264y Stat turnaround
Wairakei330274y Stat turnaround + ext works
Poihipi31284y Stat turnaround
Tauhara 14728Y3 Stat turnaround
40
Hawea storage (GWh)
Gas storage (PJ)
Closing storage
Closing storage (current)
Fuel storage movements
Source: NZX hydro
97
175
166
259
116
253
191
141
300
230
324
189
324
264
242
354
-222
-239
-231
-333
-187
-325
-293
-231
1H212H211H222H221H232H231H241H25
Inflows
Opening storage
Releases
175
166
259
116
253
191
141
264
6.1
5.0
5.8
7.8
4.7
2.4
3.4
2.8
1.6
0.8
1.7
2.4
0.5
2.7
1.7
0.9
1.3
3.1
-1.9
-0.9
-3.5
-0.7-0.7
-1.5
-2.5
-1.3
-4.3
1H212H21
-0.4
1H222H221H232H231H242H241H25
Gas Injected
Gas Extracted
Opening Storage
5.0
5.8
7.8
4.7
2.4
3.4
2.8
1.6
3.4
Operational data
Following the completion of a joint technical working group, set up by Contact and the Ahuroa Gas Storage Facility (AGS) owner
FlexGas, approximately 4.3PJs of gas owned by Contact and currently stored in AGS may only be available for extraction at the
end of the contract in 2033.
0
Long-term storage
balance (PJ)
0
0
0
4
4
4
4
4
Long-term storage transfer
41
Contracted gas volumes (PJ)
Uses of gas (PJ)
Gas storage monthly injections and extractions (PJ)
Contracted and stored gas
Gas injectedGas extracted
3.4
0.9
2.6
5.4
4.6
3.6
3.0
2.6
2.2
2.82.82.8
6.1
1.7
1.4
5.6
5.3
7.4
5.9
4.4
-0.2
5.5
5.2
0.0
CY21CY22CY23CY24CY25
CY26
CY27CY28CY29CY30CY31CY32
14.6
15.5
15.2
15.3
0.34
-0.28
Feb-
24
0.08
-0.81
Mar-
24
0.37
-0.25
Apr-
24
0.07
-0.46
0.08
-0.53
Jun-
24
0.03
May-
24
-0.77
Jul-
24
0.51
-0.25
Aug-
24
1.24
-0.01
0.35
Sep-
24
-0.21
-0.02
Jan-
24
Oct-
24
0.24
0.96
Nov-
24
0.09
-0.18
Dec-
24
-0.12
9.4
9.3
9.6
6.6
9.8
6.3
8.8
6.4
9.1
1.1
-0.7
-2.0
3.1
-2.0
-1.0
0.6
1.3
-1.7
-8.2
-6.7
-4.4
-6.5
-3.3
-2.7
-6.7
-6.4
-4.0
-1.7
-1.4
-1.6
-1.3
-1.6
-1.1
-1.4
-1.1
-1.3
-0.6
-1.6
-1.9
-2.7
-1.4
-1.3
-0.2
-2.1
-0.5
1H212H211H222H221H232H231H242H241H25
Net extraction
(injection)
Generation
Customer sales
Wholesale sales
Purchases
Short-term gas
Swap
Maui
Pohokura
Operational data
CY2025 volumes reflect current forecasts. This is ~1PJ below contacted volumes as a result of lower actual production volumes. CY2026-32 reflects the maximum volume of gas available under contract. Forecasted volumes for these periods are
not yet available.
42
Contractual fuel position sufficient to support
expected sales position under mean hydro conditions
Fuel position
Portfolio requirements for thermal generation CY25 (TWh)
Gas supply and demand CY25 (PJ)
Includes stored gas
2.40PJ**
Hydro variation >>
*Hydro generation in FY12.
** Assumes peaker generation only (heat rate 10.5GJ/MWh) i.e., assumes TCC is not used during the period.
Geothermal
Expected
CY25
generation
Hydro in
“extreme
dry” year*
"Extreme
dry" to
"mean"
year swing
Mean
thermal
required
Maximum
thermal
required
"Mean" to
"wet" year
swing
Minimum
thermal
required
2.4
4.6
2.5
3.4
Mean Year
demand
CY25 Position
4.9
8.0
9.3
1.2
0.2
-5.0
-2.9
-0.1
-1.0
-0.3
0.0
Options in a dry year:
•Access to stored water
in Hawea
•Purchase spot gas
•Acquire generation from
ASX
•Contracted gas above
expected mean position
Options in a wet year:
•Gas swaps
•Gas sales
•Hawea storage
•Sell short term ASX
•AGS storage
Acquired
generation
AGS stored gas
Contracted gas
remaining for CY25
Mean Thermal
Retail
43
EBITDAF is Contact’s earnings before interest, tax, depreciation and amortisation, and changes in fair value of financial
instruments.
EBITDAF is commonly used in the electricity industry so provides a comparable measure of Contact’s performance.
Reconciliation of statutory profit back to EBITDAF:
6 months ended
31 December 2024
(1H25)
6 months ended
31 December 2023
(1H24)
Variance on prior year
$m%
Reported
Underlying
1
Reported
Against reported
Profit
142134153
(11)(7%)
Depreciation and
amortisation
130126(4)(3%)
Change in fair value of
financial instruments
21-5(26)(520%)
Asset write-offs and
impairments
-8(8)N/A
Net interest expense52172032160%
Tax expense595360(1)(2%)
EBITDAF
404334362
4212%
Depreciation and amortisation, net interest and tax expense are explained on the right.
Reconciliation between Profit and EBITDAF
The adjustments from EBITDAF to reported profit and
movements on 1H24 are as follows:
•Depreciation and amortisation: increased by $4m and is
linked to depreciation on Tauhara being recognised post
completion. This has been partially offset by lower usage
of thermal assets compared to 1H24.
•Change in fair value of financial instruments: includes
unrealised gains/losses associated with the new NZAS
contract which is not eligible for hedge accounting.
Expected to drive increased volatility in profit going
forward. See slide 44 for more detail.
•Net interest expense: significantly higher than 1H24 as
Tauhara was completed in 2H24 and interest in relation to
borrowings to build the project are no longer being
capitalised.
•Tax expense: for the period decreased by $1m following
lower profit before tax in 1H25 vs 1H24, partially offset by
higher non-deductible expenditure related to the proposed
Manawa transaction.
Non-GAAP profit measure
1
Underlying 1H24 figures are exclusive of the impacts of the onerous contract provision for AGS. Impacts of the onerous contract in 1H24 are as follows, EBITDAF (+$29m), interest (-$3m), tax (-$7m), NOPAT (+$19m). The provision has not been
recalculated in 1H25, however, the monthly unwind and interest impacts of the provision are included in the reported 1H25 figures as follows, EBITDAF (+$7m), interest (-$2m), tax (-$1m), NOPAT (+$4m).
44
Reconciliation of change in fair value of
financial instruments
Change in fair value offinancial instruments
Realised /
unrealised
1H251H24VarianceDescription
(A) Net market making
Realised(14)(2)12
Realised gains or losses on the settlement of
electricity derivatives entered into to meet
Contact’s market making obligations
- Market making
Unrealised
44-
Mark-to-market of open electricity derivatives
in future periods
- NZAS long-term sale CFD
(17)-(17)
NPV of the changes to the forecast forward
wholesale price path vs the wholesale path
when the contracts were agreed
- Kōwhai Park acquired PPA
3-3
- Other non-hedged movements
33-
Mark-to-market of open electricity derivatives
in future periods
(B) Unrealised movements in non-hedge effective
electricity derivatives
Unrealised(7)7(14)
Total change in fair value offinancial instruments
as per segment note (A+B)
Realised and
unrealised
(21)5(26)
Commercial hedges recognised in EBITDAF that do not qualify for hedge accounting
−Financial Transmission Rights (FTR) settlements
and Exchange for Physical (ASX)
Realised
(4)(2)(2)
Financial contracts that hedge portfolio sales
that are settled in the period
−Net settlement of NZAS contract in the period
(36)-(36)
Realised settlement (difference between the
fixed contract and spot settlement)
Change in fair value of financial instruments as per
Income statement
(61)3(64)
In the period, Contact entered into two long-term
contracts for difference (CFD) that were not eligible
for hedge accounting. These contracts relate to the
sales of electricity to NZAS and the purchase of
electricity from the under-development Kōwhai Park
solar farm (online in FY26).
As a result, movements in expected wholesale prices
when compared to forward wholesale prices when the
contracts were entered into are recognised in change
in fair value of financial instruments, increasing
volatility of Net Profit After Tax. These non-cash
movements, which relate to future periods, are
recognised in the current period.
The primary change to wholesale price expectations
in the period was the listing of the 2028 ASX contract
from October 2024, which was higher than Contact’s
internally generated price path for the same period.
45
Historical financial information
Unit1H211H22
1H23
1
1H241H25
UnderlyingReportedUnderlying
2
ReportedReported
2
Revenue$m1,1411,1419941,3061,707
Expenses
3
$m8958197378579819521,263
EBITDAF$m246322257137334362404
Profit$m7813479(7)134153142
Operating free cash flow$m15713171174138
Operating free cash flow per sharecps21.916.89.122.117.4
Dividends declared cps14.014.014.014.016.0
Total assets$m4,7384,9785,4086,0596,383
Total liabilities$m2,2122,0272,7483,3753,738
Total equity$m2,5262,9512,6602,6842,645
Gearing ratio
4
%31.119.330.638.438.6
Historic performance
1
In 1H24 Contact made reclassifications to better align with IFRIC guidance on IFRS 9 resulting in realised gains/losses from market derivatives not in a hedge relationship (includes market making activity) no longer being
reported in operating income (EBITDAF). 1H23 Expenses, EBITDAF and operating free cash flow were restated accordingly.
2
1H24 figures are exclusive of the impacts of the onerous contract provision for AGS. Impacts of the onerous contract in 1H24 are as follows, EBITDAF (+$29m), interest (-$3m), tax (-$7m), NOPAT (+$19m). The provision has
not been recalculated in 1H25, however, the monthly unwind and interest impacts of the provision are included in the reported 1H25 figures as follows, EBITDAF (+$7m), interest (-$2m), tax (-$1m), NOPAT (+$4m).
3
Includes realised gains/(losses) on risk management derivatives not in a hedge relationship.
4
Gearing ratio is calculated as: (Senior debt - including finance lease liabilities) / (Senior debt - including finance lease liabilities + Equity).
46
1H251H24
Six months ended 31 December 2024Six months ended 31 December 2023
VolumeGWAPVolumeGWAP
Note: this table has not been rounded and might not addGWh$/MWh$mGWh$/MWh$m
Electricity sales to Retail segment1,991 153304 1,989 141 280
Electricity sales to C&I777 124 97 686 118 81
CfDs – Tiwai support sales303458
PPAs62-
CfDs - Long term sales219390
CfDs and ASX - Short term sales1,265879
Electricity sales – CFDs1,849 182 336 1,727 112 193
Total contracted electricity sales4,618 160 737 4,402 126 554
Steam sales127 20 2 118 16 2
Other income62
Net income on gas sales(18)2
Net income on electricity related services10
Net other income(11)4
Total contracted revenue4,745 153 728 4,520 124 559
Generation costs
1,2
4,603 (39)(181)4,386 (32)(171)
Acquired generation cost246 (297)(73)239 (127)(30)
Generation costs (including acquired generation)4,849 (52)(254)4,624 (37)(201)
Spot electricity revenue4,603 176 812 4,386 132 579
Settlement on acquired generation246 280 69 239 130 31
Spot revenue and settlement on acquired generation (GWAP)4,849 182 881 4,624 132 610
Spot electricity cost(2,769)(208)(576)(2,675)(142)(380)
Settlement on CFDs sold(1,849)(168)(312)(1,727)(133)(230)
Spot purchases and settlement on CFDs sold (LWAP)(4,618)(192)(888)(4,402)(139)(610)
Trading, merchant revenue and losses 231 (6)223 (0)
Wholesale EBITDAF underlying
1
466358
Onerous contract provision-29
1
Wholesale EBITDAF reported466387
Wholesale segment
Segmental performance
1
Underlying 1H24 figures are exclusive of the impacts of the onerous contract provision for AGS (EBITDAF +$29m). The provision has not been recalculated in 1H25, however, the monthly unwind and interest impacts of the
provision are included in the reported 1H25 figures (EBITDAF impact of +$7m)
2
From FY24 Contact no longer reports impairments and write-offs within EBITDAF. These are now reported separately to better reflect underlying performance. Generation costs for 1H24 have been restated to exclude a
one-off write-off of $4.0m relating to peaker damage.
47
Residential electricityunit
1H221H231H241H25
Residential gasunit
1H221H231H241H25
Average connections#367,199
381,222386,540400,518
Average connections#
63,18266,79667,65870,322
Sales volumesGWh1,408
1,4451,4781,506
Sales volumesTJ
970881916884
Average usageMWh per ICP3.8
3.83.83.8
Average usageGJ per ICP
15.413.213.512.6
Tariff$/MWh251.5
261.4281.2291.7
Tariff$/GJ
32.638.141.345.8
Network, meters and levies$/MWh-115.9
-118.2-122.1-132.8
Network, meters and levies$/GJ
-16.2-20.7-20.8-25.3
Energy costs$/MWh-110.8
-128.7-149.9-164.5
Energy costs$/GJ
-11.3-10.2-9.7-10.7
Gross margin$/MWh24.8
14.59.2-5.6
Carbon costs$/GJ
-1.9-4.2-3.0-4.3
Gross margin$ per ICP95
5535-21
Gross margin$/GJ
3.23.07.85.6
Gross margin$m35
2114-8
Gross margin$ per ICP
503910670
Gross margin$m
3375
SME electricityunit
1H221H231H241H25
SME gasunit
1H221H231H241H25
Average connections#48,32347,70244,74642,563Average connections#3,9183,6563,1002,721
Sales volumesGWh392421392355Sales volumesTJ628635465336
Average usageMWh per ICP8.18.88.88.3Average usageGJ per ICP160.4173.6149.9123.5
Tariff$/MWh239.0249.2276.6294.4Tariff$/GJ18.623.129.534.7
Network, meters and levies$/MWh-113.0-113-114-121Network, meters and levies$/GJ-8.7-8.4-11.4-12.8
Energy costs$/MWh-109.0-129.8-148.0-161.7Energy costs$/GJ-11.3-10.2-9.7-10.7
Gross margin$/MWh17.06.414.611.7Carbon costs$/GJ-2-4.2-3.0-4.3
Gross margin$ per ICP1385612898Gross margin$/GJ-3.30.35.57.0
Gross margin$m7354Gross margin$ per ICP-53254828864
Gross margin$m-30.232
Telco
1
unit
1H221H231H241H25
Retail segment EBITDAF
1H221H231H241H25
Average connections#57,49874,97489,831113,324Electricity Gross margin$m412419-4
Tariff$/cust/mth71.870.472.271.2Gas Gross Margin$m13107
Network, provisioning, modems$/cust/mth-61.6-62.8-63.3-62.5Broadband Gross Margin$m4456
Gross margin$/cust/mth10.27.68.98.7Total Gross Margin$m4631349
Gross margin$m4456Other income$m3544
Other direct costs$m-1-2
Other operating costs$m-33-35-37-36
Retail segment EBITDAF$m161-1-25
Corporate allocation (50%)$m-5-11-14-19
Retail EBITDAF$m11-10-15-44
EBITDAF margins (% of revenue)%2.10%-1.80%-2.43%-6.78%
Retail segment
Historic performance
1
Telco includes both broadband and mobile from 1H24 (previously broadband only).
Data sourced from publicly available filings. Our datasets may not be complete. Automated analysis can produce errors. If you believe any data on this page is incorrect, please contact us at hello@nzxplorer.co.nz. For informational purposes only. Not investment advice.
Other issuers discussed similar conditions around this time
Matched by meaning across NZX announcement text, not keywords — based on our semantic index of announcement bodies.
- MCY — Mercury NZ Limited: Robust performance in challenging conditions2025-02-24
“FY25 EBITDAF guidance unchanged at $820m. 9.6cps interim dividend declared (3% higher than HY24). FY25 ordinary dividend guidance maintained at 24.0cps, the 17 th year of consecutive dividend growth MERCURY TAKES LEADING ROLE IN NEW ZEALAND’S ENERGY TRANSITION. 3 Business pe…”
- MEL — Meridian Energy Limited: Meridian Energy Limited 2025 Interim Results2025-02-25
“2025 INTERIM RESULTS PRESENTATION 23 MERIDIAN ENERGY26 February 2025 149 145 181 175 -5 82 88 134 184 231 233 315 359 -100 0 100 200 300 400 500 20212022202320242025 $M Financial Year ended 30 June Underlying net profit after tax InterimFinal half-yearTotal 227 145 201 191 -121 1…”
- GNE — Genesis Energy Limited: Strategy execution gaining momentum in challenging period2025-02-20
“Our demand side flexibility programme began with the launch of a 12-month hot water control trial with up to 10,000 residential customers. To date more than 5,500 customers have enrolled in the trial delivering more than 17 MW of flexibility. During the period we acquired a m…”