FY25 powered by geothermal expansion and resilience

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

18 August 2025

FY25 performance powered by geothermal
expansion and resilient risk management


Twelve months ended
30 June 2025
FY25
Twelve months ended
30 June 2024
FY24

Underlying
i
Reported Against underlying
EBITDAF
ii
$774m $872m ↑ 17% from $663m
Profit $261m

$331m ↑ 13% from $230m
Profit per share 32.7 cps

41.6 cps ↑ 12% from 29.1 cps
Operating free cash flow
iii
$434m ↑ 2% from $424m
Stay-in-business capital expenditure (cash) $110m ↓ 29% from $156m
Growth capital expenditure (cash) $363m ↓ 14% from $424m
Key strategic highlights
• Manawa Scheme of Arrangement approved (acquisition completed 11 July 2025).
• New long-term agreement to supply electricity to Fonterra, supporting electrification.
• Tauhara and Te Huka 3 geothermal stations online.
• Glenbrook-Ohurua battery, Kōwhai Park solar and Te Mihi Stage 2 under construction.
• Supported the market over dry periods.
• Medium-term gas supply secured to support generation and gas-reliant businesses.
Financial performance
Contact Energy Limited (Contact) has today reported net profit of $331 million in FY25 and
operating earnings (EBITDAF) of $872m. Reported figures include a release of the Ahuroa
Gas Storage facility (AGS) onerous contract provision of $98 million within EBITDAF ($71
million within net profit after tax). The release, which takes the onerous contract provision to
nil, is a non-cash movement reflecting improved confidence in the ability to access storage
capacity and the rising value of thermal flexibility.
Excluding the release, underlying net profit is up 13 percent on FY24 to $261 million and
EBITDAF is up 17% to $774 million.
iv
Contact’s operating result was underpinned by a 34
percent uplift in geothermal generation, effective use of risk management assets and
contracts and better alignment of long-term sales to the market price of electricity.
Hydro volatility characterised operating conditions in FY25, and gas supply continued to
tighten, with domestic production down more than 20 percent over the last calendar year.
Together, these conditions impacted wholesale pricing as more expensive thermal
generation was required to cover the reduction in hydro generation in the market.
Contact contracted additional short-term gas from Methanex and utilised its flexible gas
storage capacity at AGS to support gas-backed electricity supply. As a result, Contact was
positioned to provide risk management support to other market participants, with sales of
Contracts for Difference (CFDs) 0.5TWh above plan in FY25.

Contact Energy Ltd
2
Operating free cash flow of $434 million is up two percent on the prior year driven by
improved operating performance and reduced stay-in-business capex. These improvements
were partly offset by relatively higher levels of working capital (due to higher value and levels
of stored gas) and higher interest paid (due to reduced interest capitalisation following the
completion of Tauhara). In FY25, growth capital expenditure was $363 million as Contact
invested its entire reported net profit for the year into renewable development projects.
The Board declared a final dividend of 23 cents per share, taking the annual dividend
declared for FY25 to 39 cents per share. Shareholders will have the option to participate in
Contact’s dividend reinvestment plan at a two percent discount.
Manawa
In FY25, Contact entered into a Scheme of Arrangement to acquire Manawa Energy Limited
(Manawa). The acquisition completed on 11 July 2025 resulting in the combination of the
two businesses and, importantly for New Zealand electricity users, bringing together our
complementary, geographically diversified hydro schemes.
Through Manawa, Contact has acquired 25 hydro schemes with around 500MW of capacity
and winter-weighted generation. The schemes are complementary to Contact’s existing
Clutha Mata-au hydro scheme.
“We now have an even more diverse and resilient generation portfolio, allowing Contact to
offer more fixed price supply agreements to the market. Access to this type of hedging adds
resilience, and support, for New Zealand’s large energy users to reduce their exposure to
spot market prices in dry years,” said CEO Mr Mike Fuge.
“We’re one month into our integration with Manawa. This is a quality, well-run business with
a committed and passionate team. We are now working closely together to ensure a smooth
integration.”
Demand
Flexible demand is an increasingly important source of system resilience as the New
Zealand market reduces its reliance on thermal generation. As at 30 June 2025, Contact had
reached a total 188MW of contracted flexible demand, including 141MW already online.
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. Across
multiple demand response agreements, NZAS released ~0.8TWh to the market in FY25.
v

Renewable development
In FY25, Contact’s newly-commissioned Tauhara and Te Huka 3 geothermal plants
generated 1.5TWh of baseload renewable output, reducing reliance on thermal generation in
a challenging market. This output alone is equivalent to ~60% of the year-on-year fall in
market hydro generation in FY25.
“This year demonstrated the critical role geothermal energy plays in the country. This is
baseload renewable electricity, not dependent on the weather. Our $1.2 billion investment in
Tauhara and Te Huka 3 all comes down to this: delivering the right projects, at the right time,
for New Zealand,” said Mr Fuge.
Construction began on three new projects this year: Our 100MW Glenbrook-Ohurua BESS,
168MWp Kōwhai Park solar farm and 101MW Te Mihi Stage 2 geothermal plant.
vi
Following
on from the Tauhara and Te Huka 3 geothermal builds in Taupo, these new projects are

Contact Energy Ltd
3
bringing more investment and activity to the regions, supporting small businesses and local
employment.
Decarbonising the portfolio
Contact is committed to reaching net zero emissions from generation by 2035.
vii

Market conditions in FY25 illustrated the ongoing role that flexible thermal generation plays
to support hydro volatility in the New Zealand market. Having secured access to ~6PJ of
short-term gas from Methanex and drawing on the flexibility of the AGS gas storage facility,
Contact generated 738GWh above its expected mean thermal output for FY25.
“Contact has shown how we can effectively deploy risk management levers, including
through gas contracting and generation, to support a dry market like we’ve just seen.
Importantly, with our new geothermal assets online and Manawa generation, we expect
98%
viii
renewable output from our portfolio in a mean year going forward”.
Contact’s remaining baseload gas generation plant, Taranaki Combined Cycle (TCC), was
made available for 2025. TCC has reached end-of-life and will close at the end of the year.
Retail
Total retail connections reached 646,000 across electricity, gas and broadband, up 21,000
on FY24, with a focus on multi-product customer growth (up 7%). Retail electricity net price
has improved to partially recover rising energy and lines costs.
Supporting our customers to manage their energy usage, we continue to see growth in our
Time of Use ‘Good’ plans, with 140,000 New Zealand households taking advantage of
discounted or free off-peak energy. Since launching in August 2021, customers have
received 260 million hours of free power. Contact also expanded its Hot Water Sorter
programme to more than 20,000 customers, shifting ~4GWh of electricity load away from
peak demand periods.
Contact remains focused on supporting its customers in energy hardship and has removed
disconnection and reconnection fees under its Energy Wellbeing programme. As a result,
disconnections have dropped 30 percent year on year. Our partnership with Women’s
Refuge continues, with Contact providing free power and broadband to all refuges and
safehouses nationwide.
Outlook
Looking ahead, the next twelve months will see Contact delivering the effective integration of
the Manawa business and bringing two new renewable energy projects online. Both the grid-
scale battery at Glenbrook and the Kōwhai Park solar farm are expected online in 2H FY26.
“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. Progress will
require both visionary aspiration and the ability to remain responsive to this country’s energy
needs. We are excited about the future, and the leading role Contact is playing in New
Zealand’s energy transition,” said Mr Fuge.

– ends –

Contact Energy Ltd
4
1/ MORE INFORMATION
Investor enquiries Media enquiries
Shelley Hollingsworth Louise Wright
Head of Corporate Finance (Acting) 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 full year results announcement will be held at 11am, NZ (New Zealand)
time on 18 August 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 FY25 results webcast registration
Or access this link via our website: https://contact.co.nz/aboutus/investor-centre



i
In FY25, a release of the AGS onerous contract provision equated to $98m within EBITDAF and $71m within profit. In FY24 a net movement in
the AGS onerous contract provision equated to $12m within EBITDAF and $5m within profit. Underlying performance excludes these impacts.

ii
Refer to slide 50 of the FY25 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).

iii
Refer to Note A3 of the 2025 Full Year 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.

iv
Adjusting for one-off Manawa-related transaction and integration costs, underlying EBITDAF was $792m.
v
Based on observed volume at the Tiwai node.
vi
Partial replacement for Contact’s Wairakei A&B station.
vii
Scope 1 and 2 emissions.
viii
Based on long-term average hydrological conditions and an expectation of 200GWh to 300GWh of gas generation through the Stratford
peakers following the planned closure of TCC in late 2025.

---

1
1
2025 full year results
presentation
18 August 2025
Twelve months ended 30 June 2025

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.
Subsequent to balance date, Contact acquired Manawa Energy Limited (Manawa) on 11
July 2025 via a scheme of arrangement.Manawa was delisted from the NZX on 5 August
2025, following early bond redemption.
Contact recommends that you read this presentation in conjunction with both its market
announcements and those of Manawa Energy Limitedand the materials attached to
those announcements, and in particular the market announcements and materials
Contactreleased on the date of this presentation. These are available on the NZX
website (at www.nzx.com), for Contact only the ASX website (at www.asx.com.au) and
on Contact's or Manawa's website www.contact.co.nz or
https://www.manawaenergy.co.nz/investor-centre.
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, operating free cash flow and return on invested capital 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
FY25 highlights / Mike Fuge, CEO
Market update / Mike Fuge, CEO
Financial results and outlook / Matt Forbes, CFO
2
3
1
Agenda
33
Update on Manawa and strategic delivery / Mike Fuge, CEO
3
4
Supporting materials
33
3
5
4 - 8
9 - 15
16 - 29
30 - 39
40 - 55

4
Fonterra electrification
Contact to supply 540GWh p.a. at Whareroa by
2028 (~75% new demand)
Greymouth and OMV gas contracts
Secured up to 10PJ p.a. to CY2032
140,000 households
choosing discounted or free off-peak energy
FY25 highlights

Added to the
MSCI Global Standard Index
+17%
+13%
Continued representation within
Dow Jones Sustainability Index
Delivering for
shareholders
NPAT (underlying)
$261m up $31m YoY
EBITDAF (underlying)
$774m up $111m YoY
Dividend CPS
39c up 2c YoY
+5%
Stations online
$1.1b of projects under construction
Transaction completed
11
th
July 2025
Integration underway
Secured access to
~6PJ Methanex
gas, supporting the
market in dry sequences
Medium-term gas supply
supporting generation needs
& gas-reliant businesses
Taranaki Combined Cycle gas plant made
available for winter 2025
Tauhara
174MW
1.45TWh
Te Huka 3
51MW
0.43TWh
Delivering transformative
portfolio change
Delivering renewable
energy growth
Delivering financial
performance
Delivering for
customers
Delivering for
the market
Glenbrook-Ohurua | 100MW BESS
Te Mihi Stage 2 | 101MW Geothermal
Kōwhai Park |168MWp Solar

5
Refreshed leadership, delivering growth
Leadership team refreshed to match the scale, complexity and ambition of the business
Mike Fuge
Chief Executive
Officer
•Jack Ariel, Major Projects
Director, retired.
•Matt Forbes appointed Chief
Financial Officer.
•Carolyn Luey appointed Chief
Retail Officer.
Jan Bibby
Chief People
Experience Officer
Chris Abbott
Chief Corporate
Affairs Officer
John Clark
Chief Generation Officer
Tighe Wall
Chief Technology Officer
Matt Bolton
Manawa Integration Director
Dorian Devers
Chief Renewable
Growth Officer
Changes
(During 2H FY25)
Matt Forbes
Chief Financial Officer
Carolyn Luey
Chief Retail Officer

6
1
In FY25, the release of the AGS onerous contract provision increased reported EBITDAF by
$98m and profit by $71m. In FY24 the net movement in this provision added $12m to EBITDAF
and $5m to profit. This is the only adjustment from reported to underlying performance.
All variances and commentary reflect year-on-year changes in underlying performance.
2
Refer to slide 50 for a definition and reconciliation of Profit to EBITDAF.
Summary of key financial performance measures
Building for the future, ready for today
Performance powered by geothermal expansion and resilient risk management
FY25 was shaped by challenging market dynamics:
•Two historically significant dry periods
reduced hydro output and increased reliance on
thermal generation.
•Gas production fell 20% year-on-year,
deepening fuel scarcity.
•Spot and short-term futures prices spiked,
then eased as inflows recovered and Methanex
gas was secured.
•Lines charges rose ~20% from April 2025,
adding further cost pressure.
Contact’s diversified portfolio and proactive risk
management supported strong performance in a
volatile year:
•Geothermal output rose 34%, with Tauhara and
Te Huka 3 delivering 1.5TWh of reliable baseload
energy.
•TCC was retained to support winter 2025,
despite being scheduled for closure.
‒Combined with AGS storage, this enabled
Contact to secure Methanex gas and supply
renewable-only generators during dry
periods—helping stabilise the market.
Market
FY25 highlighted several medium-term challenges:
•Ongoing gas scarcity with limited options to
increase gas supply.
•Rising costs for long-term risk management
products.
•Growing seasonal price spreads, especially
between summer and winter.
•Increased price volatility as more intermittent
generation enters the market.
Medium term
Contact is well-positioned for medium-term market
conditions:
•Renewable build-out progressing across solar,
geothermal and battery projects.
•Manawa acquisition adds portfolio flexibility and
favourable market channel exposure.
•Long-term gas contracts to 2032 support
intermittent generation and key customers.
•Strategic customer partnerships support
decarbonisation.
3
ROIC is four-year average. See slide 25 for the operating free cash flow reconciliation and for the basis of calculation of return on invested capital.
For FY24, $46m of growth capex has been reclassified to stay-in business capex, ensuring that spend is classified according to which assets
receive the most benefits under a revised scope of Te Mihi Stage 2.
4
Relates to interim and final FY25 dividends declared.
5
Includes capitalised interest.
Twelve months ended
30 June 2025 (FY25)
Twelve months ended 30
June 2024 (FY24)
Underlying
1
ReportedAgainst underlying
1
EBITDAF
2
$774m$872m↑17% from $663m
Profit$261m$331m↑13% from $230m
Profit per share32.7 c41.6 c↑12% from 29.1 c
Operating free cash
flow
3
$434m↑2% from $424m
Operating free cash flow
per share
3
54.4 c↑1% from 53.9 c
Average ROIC
3
4.9%↑From 3.7%
Dividend declared
4
$355m↑22% from $292m
Dividend declared per
share
4
39.0 c↑5% from 37.0 c
Stay-in-business (SIB)
capital expenditure
(cash)
$110m↓29% from $156m
Growth capital
expenditure (cash)
5
$363m↓14% from $424m
FY25

7
Delivering on the plan
FY25 operational plan
Grow renewable
development
Decarbonise
our portfolio
Create
outstanding
customer
experiences
Strategic theme
Grow
Demand
Impressive delivery of the FY25 strategic targets outlined at the start of the year
FY25 achieved
▪New demand facilitated since FY21 to
reach >120MW.
▪Achieve FID for CO
2
.
▪Add 15MW of flexible demand.
▪Achieve FID for Te Mihi Stage 2.
▪Lodge consent for Stratford solar.
▪Achieve consent on Glorit solar.
▪Achieve consent on Southland Wind.
▪Te Huka 3 online Q4 CY2024.
▪Glenbrook-Ohurua BESS
1
on-track for
online Q1 CY2026.
▪Kōwhai Park solar on track for online for
Q2 CY2026.
▪Additional investment in carbon offsets.
▪Close TCC
2
gas generation plant.
Expected to close December 2024.
▪Sustained entry into the DJSI.
▪Electricity net price up by 2-3%.
▪Multi-product customers >149k (up from
140k).
▪Target cost to serve <$123/connection.
3
▪Scale Hot Water Sorter programme to
>20k homes (up from ~5k).
Complete /
on-track
Minor delay and / or
cost increase
Major delay and / or
cost increase
Key:
New demand facilitated and contracted since FY21 ~230MW (88MW online) up from 105MW.
15MW of additional flexible demand contracted, taking total contracted volume to 188MW (141MW online).
CO
2
Final Investment Decision (FID) now targeted for FY26.
Glenbrook-Ohurua BESS under construction. Expected online in Q1 CY2026.
Achieved FID on Te Mihi Stage 2 geothermal station. Expected online in Q3 CY2027.
Consenting process underway for Glorit solar. Earliest expected FID FY26.
Consent declined under COVID-19 Fast Track. Contact has been accepted under the new Fast Track
Approvals Act and expects to lodge a substantive application shortly.
TCC made available for Winter 2025 to support security of supply. Closing 2025.
Up >3%; full recovery of lines cost increases; partial recovery of rising wholesale costs.
More than 149k multi-product customers, up ~7%.
Cost to serve $116 / connection.
Reached >20k homes in the programme and shifted 4GWh residential demand off-peak in FY25.
Sustained inclusion in DJSI Asia-Pacific (one of only five New Zealand companies).
Purchased additional ~8% interest in Forest Partners (taking total to 22%).
Te Huka 3 online December 2024 at 54MW operating capacity. Final commissioning completed June 2025.
Kōwhai Park solar under construction. Expected online in Q2 CY2026.
Consent lodged for Stratford solar.
1
Battery Energy Storage System.
2
Taranaki Combined Cycle.
3
Includes customer acquisition costs.
Strategy delivery

8
Renewable projects under construction
Target scheduleOnline in Q1 CY2026
1
Battery Energy Storage System.
2
Includes sunk cost of $66m and $5.4m for Te Mihi Stage 2 and Glenbrook-Ohurua BESS respectively. Excludes capitalised interest.
3
Excludes financing costs of $43m. Includes development costs.
Key facts & progress updates
Contact is currently leading the build of ~$1.1bn in renewable infrastructure across New Zealand
Battery capacity / storage
100MW / ~200MWh
Up to $163m
2
Total project costs
Te Mihi Stage 2 geothermal
Glenbrook-Ohurua BESS
1
Kōwhai Park solar farm
4
▪All 28 transformers and 56 Megapacks are now installed on site.
▪Electrical connections between Megapacks and transformers are
well advanced.
▪Balance of plant works—including switch and control rooms,
cabling, and auxiliary transformers—are progressing well.
▪Concrete foundations for key infrastructure are largely complete.
Progress update
Target scheduleOnline in Q3 CY2027
Net capacity / annual generation
101MW / 0.8TWh
$712m
2
Total project costs
▪Earthworks are nearing completion.
▪The power station site has been handed over to the EPC
contractor, with foundation trenching and excavation now
underway.
▪Wairakei extension works have commenced, including planning
for major upgrades to electrical reticulation systems.
Progress update
▪Construction village and earthworks are well advanced.
▪Most PV modules, trackers, and inverters are now on site.
▪The first row of solar panels—the “golden row”—has been
successfully installed.
Progress update
Target scheduleOnline in Q2 CY2026
Net capacity / annual generation
168MWp / 0.3TWh
$273m
3
Total project costs
4
The Kōwhai Park solar farm is part of Contact’s 50/50 JV with Lightsource bp.
Strategy delivery

9
Market update

10
National electricity demand
Source: EMI, Contact.
Does not include NZAS.
National electricity demand (TWh)
Regional
change (%)
FY25 vs FY24
Source: EMI, Contact.
NZAS demand response is estimated by comparing total demand in FY25
against average demand at the Tiwai node over the preceding 4 years.
Market demand
NZ electricity demand down ~1% even when normalised for NZAS demand response
National electricity demand in FY25 reflected the
impact of extreme weather and challenging conditions.
Overall demand was down ~3% year-on-year, driven
by dry conditions and demand reductions from
customers exposed to fuel scarcity though high prices.
Adjusting for NZAS demand response—called by
Meridian to support lower hydro conditions—
underlying demand fell ~1%.
Notable regional changes included:
•A 58% drop in demand at the central North Island
node following the closure of the Winstone Karioi
pulp mill and Tangiwai sawmill in August 2024,
reflecting broader challenges in wood and paper
processing without the protection of fixed price
electricity hedging.
•A 12% decline in South Canterbury, concentrated
in irrigation nodes, driven by high inflows between
September and December 2024.
•A 16% increase on the East Coast, as Pan Pac’s
Whirinaki plant—closed after Cyclone Gabrielle in
2023—gradually resumed operations through 2H24
and 1H25.
(3%)
(4%)
1%
(12%)
(6%)
(3%)
(1%)
(2%)
9%
0%
(3%)
(1%)
(58%)
(1%)
(0%)
1%
(0%)
2%
16%
5.1
4.9
5.0
5.0
5.0
4.2
10.3
10.6
10.2
10.5
11.2
10.9
25.8
26.1
25.8
25.6
25.9
25.7
FY20FY21FY22FY23FY24
0.8
FY25
41.2
41.6
41.1
41.1
42.1
41.6
+1%
-1%
NZAS demand response
North Island
South Island (ex NZAS)
NZAS
40.9
-3%

11
Near term demand outlook is positive
Committed new load and consistent residential progression accounts for more than half of market growth
expectations in the next 5 years
20202021202220232024202520262027202820292030
0
41
42
43
44
45
46
47
48
Calander year
NZ Electricity Demand (TWh/year)
+0.3%
CAGR
2
Estimates of future demand by sector
3

National demand growth over time
1

Future demand sources committed growth
Residential decarbonisation & EV uptakeAdditional / faster industrial electrification Data centres
Additional and / or faster industrial decarbonisation resulting
from higher cost and less available natural gas
1.3%
CAGR
2
Faster EV uptake and residential decarbonisation
(heating / cooling)
Data centre build out consistent with
current pipelines / projections
1.1
0.9
1.2
2024
actual
Dairy
0.2
MetalsData
centres
Residential2030
identified
Future
projects
46.2
2030
EDGs
44.9
3.3
41.6
+8.0% total
identified growth
ResidentialDairyMetalsData centres
Actual demand data (EMI)
Contracted / under construction demand
MBIE EDGs 2024 – Reference scenario
Market demand
+1.3
TWh
Known
&
committed
Market
interest
1.7%
CAGR
2
1
MBIE EDGs reference case used as a proxy for market expectations given its use by Transpower for capital investment planning.
2
Compound annual growth rate.
3
Forecast does not include assumptions around potential industrial demand loss or line losses.

12
Supply Commentary –
Generation Mix FY25
•Hydro generation was down
~10% on FY24, 9% below the post-
market mean and the lowest annual
volume since 2008. This reflected
two historically dry periods,
including record-low inflows
between January and March 2025.
•Gas generation increased to
support the market, enabled by
short-term gas from Methanex,
which paused methanol production
to make supply available.
•Geothermal rose with Tauhara and
Te Huka 3 contributing 1.5TWh—
geothermal delivers twice what
wind does.
•Solar increased from 10GWh to
100GWh, ~0.2% of total market
generation.
•FY25 highlighted the importance of
flexible, dispatchable generation
and strategic fuel reserves in
managing volatility and supporting
the transition to renewables.
Generation by type (TWh)
Hydro Storage – FY25 Summary
Hydro storage was highly volatile across the year:
•The financial year began with storage well below average due to low inflows in late FY24.
•Heavy rainfall in August lifted storage to a peak in December.
•From January to March, total inflows (across Taupo, Waitaki, Clutha and Te Anau) were the lowest in 99 years.
•With gas supply tight, the market conserved hydro storage ahead of winter 2025.
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
Jul-
23
Dec-
23
Jul-
24
Dec-
24
Jun-
25
1H24 1H25
Storage
TWh
National hydro storage

Carbon
emissions (mT)

Source: EMI (generation data), MBIE (emissions data) and NZX Hydro data.
1
Carbon emissions for FY25 Apr-Jun quarter has been estimated using historic conversion rates with actual generation data.
Two historically significant dry periods
Fuel supply
Lower hydro output offset by new geothermal production and lower demand
2H252H24
3.1
2.9
2.7
2.5
7.1
3.5
3.7
27.0
7.6
9.0
23.9
21.4
3.1
2.4
1.7
3.9
4.2
0.5
FY23FY24FY25
Gas
Coal
Hydro
Geothermal
Wind
Solar
Other nonidentified
generation
43.1
44.1
42.9
4.1
1

2.3
4.2
1
2
1. Winter 2024
2. Summer 2025
MeanActual

13
Net domestic gas production
Volatile pricing driven by hydro and gas availability
Wholesale and futures electricity pricing ($/MWh)
Wholesale market
0
50
100
150
200
250
300
350
400
450
500
Jun-
16
Jun-
17
Jun-
18
Jun-
19
Jun-
20
Jun-
21
Jun-
22
Jun-
23
Jun-
24
Jun-
25
10 year
average
spot price
$126
Long-dated futures (>12 months)
Short-dated futures (<12 months)
Monthly average spot price
Source: EMI wholesale pricing
Pricing Commentary – FY25
•Spot and short-term futures prices spiked during two dry periods—Winter 2024 and Summer 2025—driven by low hydro inflows, limited wind, and a 20% year on year reduction in gas supply.
Prices eased as hydro inflows recovered and Methanex gas was made available for generation.
•Long-dated futures rose in response to declining domestic gas forecasts (down by 20% on average) and the rising cost of firming intermittent renewables. While the HFO agreement (including a
strategic reserve at Huntly) helps reduce scarcity risk, prices continue to reflect the cost of dispatchable fuel—whether gas, coal, or demand response—needed to meet winter demand.
0
2
4
6
8
10
12
14
MayJunJulAugSepOctNovDecJanFebMarApr
20242025
PJ
1
2
Source: MBIE gas statistics; 2P reserves data.
0
50
100
150
202520262027202820292030
2024 forecast2025 forecast
Average annual forecast production (2025 – 2030)
Average monthly gas
production down 20%
year-on-year
Latest annual production
forecasts stepped down 24%
on average
Current gas deliverability forecasts point to continued steep decline

14
Retail Electricity Market Connection Trends
•Competition remains strong, with churn steady at ~19% despite elevated
wholesale prices.
•Tier 1 retailers now hold ~85% market share. Growth over the last 2 years
was led by Meridian (+12% over two years, excluding Flick), followed by
Genesis (+4%) and Contact (+5%). Mercury remained stable.
•Meridian’s acquisition of Flick Energy (announced May 2025) adds ~41k
connections, though these are not yet reflected in reported market share.
•Tier 2 retailers are losing ground, with most stepping back from customer
acquisition. Flick (+27%) and 2Degrees (+9%) were exceptions.
•Contact added 20k residential connections over the past two years,
reaching 20% market share.
Change in retail customer electricity connections (000s)
30 June 2023 – 30 June 2025
2yr % change2yr ICP delta (1000s)
Retail electricity tariff changes (c/ kWh)
Tier 2: -9k connections
Retail Pricing Trends
•Residential electricity prices have risen steadily, with a compound annual
growth rate of ~4% over the past five years to March 2025. The average
increase in the year to March 2025 was ~4%.
•Cost pressures are expected to continue. Key drivers include:
‒Higher wholesale electricity prices, particularly in winter when
usage is highest.
‒Increased cost of transmission and distribution infrastructure.
2
These factors are expected to keep upward pressure on retail prices over
the near term. Continued investment in new renewable generation is
expected to bring down electricity costs over time.
12 months
ended:
Tier 1: +66k connections
Source: EMI – residential ICPs only
Source: MBIE
18.2
18.6
19.5
20.7
20.9
11.1
11.6
12.0
12.4
13.5
Mar-21Mar-22Mar-23Mar-24Mar-25
29.4
30.2
31.5
33.1
34.4
+4%
Retail strategic value outweighs margin headwinds
Retail electricity market
Medium-term cost pressures not deterring long-term positioning or competition
Lines (c/kWh)Energy & Other (c/kWh)
1
1
Compound annual growth rate.
4%
5%
0%
12%
-3%
-6%
27%
9%
8%
-20
0
10
20
30
-30
GenesisContactMercuryMeridianNovaPulseFlick
-21%
Electric Kiwi2Degrees/
Vocus
Other
2
From 1 April 2025, Commerce Commission-approved changes to network charges began to take effect, increasing household bills by $10–$25 per month on average
(depending on region and usage profile).

15
Responding to the energy challenges that matter
Investing at
pace
Making the most
of favourable
consenting
environment
Fuel security
and dry year
risk
Regional
growth
Energy
wellbeing
▪Generation totalling 6.7TWh
built or committed by industry
between 2020 and 2027.
▪335MW of grid-scale batteries
now online or under construction
in New Zealand.
▪Industry-wide focus on energy
wellbeing and reducing
punitive practices.
▪Disconnections now viewed as
last resort.
Contact is investing in renewables, flexible storage, and demand response - guided by clear market signals and
long-term national priorities; These actions reflect strong alignment with government objectives and reinforce
the value of stable, predictable policy settings
1
Based on observed volume at the Tiwai node.
2
HFO agreement is subject to Commerce Commission review.
Leading sustainable decarbonisation in the transition to Net Zero 2050
We are anticipating the government’s response to the review of electricity market performance in September
We expect this to propose sensible market enhancements to improve outcomes for consumers
▪Removed all disconnection and
reconnection fees and financial
barriers for reconnection.
▪Free power and broadband to all
Women’s Refuge safehouses and
refuges nationwide along with
other targeted social agencies.
▪225MW of baseload renewables
brought online at Tauhara and
Te Huka 3 geothermal stations
in CY 2024.
▪Investments in battery and solar to
come online in CY 2026. Te Mihi
Stage 2 to come online CY 2027.
▪Fast Track Approvals Act passed
into law.
▪Changes to national policy
statements proposed.
▪Replacement Resource
Management legislation to be
introduced before end of year.
▪Contact and Manawa together
can move at pace on a robust
pipeline of consentable
developments and reconsents.
▪Engaging on RMA reforms,
including seeking automatic
reconsent for schemes <50MW.
▪Entered 50MW HFO agreement.
2
▪Secured up to 10PJ p.a. gas supply
to CY 2032 with option to extend.
▪Improved performance of AGS gas
storage enhances flexibility.
▪NZAS demand response
activated, releasing ~0.8TWh to
the market in FY25.
1
▪Signed 10 year, 150MW HFO
agreement keeping rankines
available for dry year risk.
2
▪Methanex short-term gas
interruptibility achieved.
▪Major renewable developments
underway creating jobs in the
regions. Including Southland,
Central North Island, Hawkes
Bay, Northland and wider.
•Contact’s geothermal
development programme has led
to job creation in Taupo region.
•Tauhara alone involved 2.65
million work hours with over 4,000
people helping to build it.
Market
Contact

16
Financial results
and outlook

17
Key themes from the financial results
FY26 normalised and expected
3

EBITDAF of $980m (or $945m after
transaction and integration costs), up
from the initial $770m in FY25.
Improved confidence in the ability to
access AGS storage capacity, and the
rising value of thermal flexibility, increased
the value of the AGS contract and led to
the removal of the non-cash provision.
TCC and AGS storage enabled
Contact to secure ~6PJ of short-
term gas from Methanex, supporting
renewable generators during dry
conditions.
New NZAS contract delivered
improved pricing, enabled demand
response during dry conditions,
and provided long-term certainty to
support renewable investment.
1
1
Net cost of NZAS demand response to Contact in FY25 was $22m.

Includes fixed and variable payments to NZAS and the NZAS CFD revenue foregone, net of assumed spot sales.
2
Reported EBITDAF, including AGS onerous contract provision release of $98m, was $872m.
3
Normalised and expected EBITDAF assumes mean hydrology and wind for the year and assumes planned asset availability / capacity i.e. adjusts for planned in-year outages (e.g. geothermal statutory outages, hydro refurbishments).
Delivered 1.5TWh of new baseload
geothermal from Tauhara and Te
Huka 3; Contact’s hydro generation
was 15% below mean.
Underlying EBITDAF $774m
2

($792m before Manawa-related costs);
ahead of normalised and expected EBITDAF.
Delivering
value from fuel
flexibility
Delivering value
from renewable
generation
growth

18
133
151
98
12
663
46
-185
-3
15
-46
774
675
-31
872
111
49
71
5
-18
-65
-10
-33
-3
235
-43
331
230261
Profit ($m)
1
Performance underpinned by renewable growth, fuel flexibility, and pricing discipline
Strong earnings growth reflects investment
Underlying EBITDAF ($m)
1
Gas and acquired
generation costs
rose $85/MWh to
$200/MWh (+72%),
driven by short-term
Methanex
purchases and
NZAS demand
response.
Market channel
pricing up
$36/MWh to
$186/MWh (+24%),
driven by higher
realised C&I, CFD
and merchant
prices in a fuel-
constrained market.
Renewables up
0.8TWh, with 1.2TWh
more geothermal from
Tauhara and Te Huka 3
offsetting 0.3TWh lower
hydro—reducing
reliance on thermal and
acquired generation
($200/MWh). Partly
offset by a volume mix
shift to longer-term
sales channels.
Opex higher,
including transaction
and integration costs
($18m) and for new
plants online; partly
offset by non-cash
AGS unwind ($15m).
5
3
1
FY25 results: Summary
FY24 profit
Net
interest
costs

EBITDAF
Depreciation
& Amortisation
Tax

Change in
FV of
financial
instruments
FY24 EBITDAF
4. Gas, carbon and
acquired
generation cost
6. Fixed
costs
FY25 EBITDAF
Long-term channel
pricing rose
$9/MWh to
$136/MWh (+7%),
reflecting improved
NZAS contract
terms from 1 July
and retail pricing
moving closer to
long-run
expectations.
2
Other income was
lower in the period
reflecting loss on
sale of gas.
6
3. Market
channel
pricing

FY25 profit
AGS onerous contract release
Underlying EBITDAF
AGS onerous contract release (after tax)
Underlying profit
Realised change in FV of financial instruments
Unrealised change in FV of financial instruments
2. Long-term
channel
pricing
5. Other
income
4
1
Movements in profit and EBITDAF are shown on an underlying basis. For FY24, this excludes all impacts of the AGS onerous contract provision—EBITDAF increased by $12m, interest decreased by $5m, tax decreased by $2m, and NPAT increased by
$5m. For FY25, underlying figures include the cumulative impact of monthly provision unwinds—EBITDAF increased by $15m, tax decreased by $4m, and NPAT increased by $8m—but exclude $98m from the release of the provision.
2
In FY24, Contact recognised $50m of write-offs, primarily relating to peaker engine damage, Tauhara assets impacted by the 2023 steam hammer event and valve failures, and software assets from discontinued HRIS and CRM projects. In FY25, a
further $1 million was written off, relating to capital work in progress and inventory.
Asset
impairment
/ write-offs
2
1. Renewables
and sales
volumes

19
Wholesale EBITDAF
1
(underlying, $m)
Retail EBITDAF ($m)
Corporate / unallocated costs ($m)
Operating performance by segment
Wholesale business performance offsets retail losses
and integration-related costs
Refer to slides 20 - 22
Refer to slide 23
68
215
FY24Generation
costs
(including
acquired
generation)
Total
contracted
revenue
3
Trading,
merchant
revenue
and losses
FY25
746
895
+149
-32
-49
FY24
0
Electricity
Volumes
77
96
Electricity
Prices
2
Other
products
2
0
OpexFY25
-17
Electricity gross margin
(-$19m)
Electricity
and network
cost inflation
Price recovery
2
Other products includes retail gas and telco gross margins.
FY25 results: Segmental performance
1
Simply and Western included within Wholesale EBITDAF.
Underlying EBITDAF is shown excluding a net $12 million AGS onerous contract
provision movement in FY24 and a $98m provision release in FY25.
3
Stats NZ CPI increase over the 12 months to June 2025 plus
wage inflation.
4
Net of $4.3m of Manawa transaction costs incurred in FY24.
-51
-55
-73
FY24
2
Inflation
2
Growth &
performance
FY25
before
Manawa
costs
18
Manawa
Transaction
and
Integration
Costs
FY25
-22
3
4

20
Electricity generated or acquired (GWh)
Generation costs rose despite strong geothermal growth, reflecting elevated gas and demand response costs
FY24FY25
Electricity generated or acquired costs ($m)
Generation costs
FY25 results: Wholesale business
Gas and diesel
Acquired
Thermal
Renewable
Gas storage
1
Carbon costs
Electricity and gas
transmission and levies
Other operating costs
Generation volumes
•
FY25 saw two distinct periods of historically low hydro inflows. The
result was a reduction in hydro generation of 331GWh (9%) when
compared to FY24 and 603GWh below mean (~15% vs 3,900GWh).
•
Geothermal volumes were up 1,156GWh on FY24 (34%). This
increase was a result of Tauhara being operational for the entire
period and Te Huka 3 being operational for 2H25. Their 1.5TWh
contribution was partly offset by statutory outages at other stations.
•
While thermal generation was required to support periods of low hydro
inflows, particularly in Winter 2024 and Q1 2025, it was down on FY24
by 532GWh as the geothermal stations were online.
•
While acquired generation was used to help cover supply risk from
reduced hydro inflows in FY25, total volume was down 123GWh on
FY24. Costs, but not volume associated with the call on NZAS
demand response FY25 are captured in acquired generation.
Costs
•
Renewable generation costs were up $23m (18%) on FY24 due to the
costs of operating new stations ($7m within opex), geothermal outage
acceleration, higher transmission costs and rates.
•
Thermal generation costs, were up $15m (7%) on increased average
cost of gas as a result of short-term purchases in a constrained market
(FY24: $8.5/GJ, FY25: $15.4/GJ).
•
Acquired generation costs were up $29m (31%) despite lower volume.
Reflects NZAS demand response payments of $35m
2
and no
associated volume recognised (FY24: $159/MWh, FY25: $264/MWh).
3,388
4,543
3,628
3,297
1,620
1,088
585
462
FY24FY25
Acquired
Thermal
Hydro
Geothermal
9,220
9,390
114
134
126
34
149
37
218
113
233
143
93
62
122
61
27
93
122
5
Generation
type
Cost
type
8
Generation
type
14
Cost
type
443443
511511
+68
81%
Renewable % of
own generation
88%
$48.02/MWh
$54.40/MWh
1
Gas storage costs exclude the $12 million net movement in the AGS provision in FY24 and
the $98 million provision release recognised in FY25. In FY25, gas storage costs include a
$14.6 million provision unwind released throughout the year.
Development
Acquired generation
costs
2
Total payments to NZAS. Does not account for foregone revenue from
NZAS on the demand response volume nor any associated sales opportunity.

21
562
601
163
169
376
471
67
146
11
3
-11
FY24

4
5
-9
FY25
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
1,171
1,386
+215
3,689GWh
$162.9/MWh
Contracted
revenue ($m)
Diversified mix of long-term and ASX linked sales channels
2,297GWh
$204.9/MWh
-112GWh
+$15.15MWh
-276GWh
+$58.6/MWh
Contracted wholesale revenue increased across most channels, supported by
higher prices and strategic volume shifts.
•Sales to the retail segment were 112GWh lower than FY24, with warmer
conditions reducing usage per connection. The electricity transfer price rose by
$15/MWh to $163/MWh—reflecting higher wholesale prices over the past three
years—resulting in a $39 million increase in revenue.
•C&I channel sales were marginally higher in FY25 (+41GWh) with fueling
limitations in Winter 2024 and early 2025 reducing the ability to sell additional
volume in the period. Net price improved slightly (+$0.2MWh) reflecting customer
contracts repricing closer to the prevailing ASX price during the period.
•CFD volumes fell by 276GWh as more sales volume was allocated to long-term
strategic channels. This was partly offset by a large risk management contract
sold to Meridian in 1H25. CFD pricing rose by $58.6/MWh to $205/MWh,
reflecting the market conditions.
•Strategic fixed price volumes rose by 508GWh, driven by new PPAs linked to
Tauhara and higher contracted volumes to NZAS. This was partly offset by NZAS
demand response during the period. Pricing for these sales increased by
$29.5/MWh, reflecting both the Tauhara-backed PPAs and a full year of sales
under the new NZAS agreement effective 1 July 2024.
•Other income was lower due to a loss on gas sales, driven by a materially higher
weighted average cost of gas following purchases from Methanex in early FY25.
Wholesale contracted revenue
1,170GWh
$144.1/MWh
+41GWh
+$0.2/MWh
FY25 results: Wholesale business
1,727GWh
$84.7/MWh
+508GWh
+$29.5/MWh
Year-on-year
changes to
volume and price
FY25 volumes
and price

22
Trading EBITDAF ($m)Long / short position (GWh)
$178.4/MWh
4.8%
($8.5 / MWh)
9.0%
($7.4 / MWh)
In FY24, hydro volatility and elevated spot prices led to
reduced hydro generation and increased reliance on
higher-cost thermal, resulting in lower merchant
generation compared to FY23. This trend continued in
FY25, with merchant generation remaining broadly flat
year-on-year.
FY25 conditions were shaped by:
•Historically low hydro inflows, significantly reducing
hydro output.
•Lower wind generation, compounding the supply gap.
•Elevated wholesale spot prices throughout the year.
•Significant demand response from NZAS, helping
reduce system demand during tight periods.
•A shift away from merchant exposure, as short-dated
electricity sales contracts were used to de-risk
material gas arrangements.
The LWAP/GWAP spread widened to 9%, reflecting
volatile market conditions, including periods of higher
South Island prices and periods where generation at
thermal nodes was concentrated (suppressing pricing).
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
$197.9MWh
Spot purchases and
sell CFD settlement
Spot sales and buy
CFD settlement
Merchant generation
91
100
-73
-80
FY24FY25
18
20
513
507
8,707
-8,707
FY24
8,883
-8,883
FY25
513
507
FY25 results: Wholesale business
LWAP/GWAP
losses

23
1
Retail business performance
EBITDAF ($m)
Managing through rising wholesale input costs while growing market share through a multi-product strategy
Revenue & Tariff
1
($m)
FY25FY24Variance
$mTariff$m$mTariff
Electricity revenue
1,079$312/MWh1,01861+$25/MWh
Gas revenue
103$49/GJ967+$8/GJ
Telco revenue
101$72/Mth8219-
Other income
710-3
Total revenue
1,2901,20684
Contract Asset (closing)
330
# of connections (closing)
1
642k621k
Cost to serve/connection
2

$116$123
1
Retail connections only, excludes Simply Energy.
2
Reflects total operating costs (direct and indirect) / average connections. Includes customer
acquisition costs.
10
13
8
18
17
7
-11
-74
-74
FY24FY25
Other
Gas GM
Electricity GM
Telco GM
Other operating
expenses
-32
-49
4
-17
Gross Margin (GM) is Revenue less Cost of Goods
(Networks, meters, levies, energy, carbon and telco)
3
Input costs shown per MWh at the GXP.
FY25 results: Retail business
Retail margins have contracted, driven by sustained high wholesale
prices and rising distribution costs.
•Retail EBITDAF decreased by $17m on FY24 largely driven by
the $96m increase in electricity input costs that were not fully
passed through to customers.
The average retail electricity tariff increased by 8.8% reflecting
targeted retail price rises to partially offset rising wholesale costs
and full recovery of lines cost increases.
•Around 91% 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 and distribution infrastructure.
4
•Continued elevated wholesale futures prices.
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 +21k on FY24with telco up 15k and energy
up 6k.
•Multi-product customers up 7% on FY24, driven by strong telco
product attachment alongside ToU Good plans growth.
Cost to serve – reduced by $7/connection, largely driven by
increased connections, lower marketing spend and productivity
improvements through continued growth in digitised interactions,
partially offset by wage inflation.
73k
109k
439k
FY24
73k
124k
445k
FY25
Gas
Telco
Electricity
621k
642k
Closing connections (k)
Electricity
transfer price
3
$148/MWh$164/MWh
Networks,
meters and
levies
3
$118/MWh$132/MWh
4
From 1 April 2025, Commerce Commission-approved changes to network charges
began to take effect, increasing household bills by $10–$25 per month on average
(depending on region and usage profile).

24
Other operating cost movement ($m)
Base
movement
Non-recurring and performance items
•FY24 included $4 million of one-off costs related to assessing the Manawa
acquisition (in addition to costs for cyclone repair and restructuring).
•In FY25, non-recurring spend outside of Manawa included feasibility costs for the
Wairakei extension, SAP Ariba implementation and restructuring. FY25 saw an
increase in employee incentives, reflecting strong performance outcomes.
Base movement
•General inflation contributed approximately $3 million (2.7%). However, several
key cost categories rose faster than inflation:
•Labour costs increased by 3.5%, including $5 million for staff
development under the Grow Your Whānau parental support programme.
•Rates rose by 36% ($1 million).
•Staff benefit costs higher—including medical insurance, electricity
subsidy support, and increased retirement contributions— to support
capability retention.
•Insurance costs increased by 20%, although this was partly offset by
changes to the insurance programme structure.
•Productivity improvements in the Retail and C&I businesses helped
mitigate some of these cost pressures.
Growth
•Retail connection growth added $1 million in operating costs.
•Tauhara and Te Huka 3 contributed $7 million in additional operating expenditure.
•A further $2 million was invested in feasibility work for future geothermal, wind,
and solar development.
Operating costs reflect inflation, growth, and one-
off items related to the Manawa acquisition
General cost inflation
Growth
FY25 results: Other operating costs
Headwinds
FY25 One-off Impacts
FY24 One-off Impacts
5
10
11
10
7
2
4
Non-recurring
3
0
Base movementGrowthUnderlying
Opex
FY25 Manawa
Related Costs
FY25
Reported
253
0
13
276
18294
FY24
Non-recurring
and
performance
Productivity savings
Manawa Costs
FY25 Performance
Integration Costs
Transaction Costs

25
•Higher underlying EBITDAF, as detailed on slide 18.
•Working capital change was a negative $35m impact to OpFCF (vs. positive $31m in FY24),
mainly due to increased gas inventory purchases—both in volume and cost per GJ.
•Tax paidwas $9m higher, reflecting stronger operating profit and the July 2024 final wash-up
payment for FY24.
•Interest paid, net of capitalised interest, rose by $56m. This was driven by the commissioning
of Tauhara, which reduced the amount of interest eligible for capitalisation compared to FY24.
12 months
ended
30 June 2025
12 months
ended
30 June 2024
Comparison
against FY24
EBITDAF (underlying)$774m$663m↑$111m
Working capital changes($35m)$31m↓($66m)
Tax paid($106m)($97m)↓($9m)
Interest paid, net of interest capitalised($77m)($21m)↓($56m)
SIB capital expenditure
1
($110m)($156m)↓$46m
Non-cash items included in EBITDAF($12m)$4m↓$16m
Operating free cash flow
1
$434m$424m↑$10m
Operating free cash flow per share54.4 c53.9 c↑0.5 c
Cash conversion (OpFCF / underlying
EBITDAF)
55%64%↓down 9%
Return on invested capital (ROIC)
Cash conversion lower with strong EBITDAF growth offset by negative working capital changes and interest
Cash flow and capital expenditure
Sources and uses of cash ($m)
FY25 results: Cash flow
14620017496251
NOPAT - $m
1
Pre-FID costs associated with Te Mihi Stage 2 have been reclassified as SIB capex in FY24 ($46m). These were previously allocated to growth capex. FY24 operating cash flow has been adjusted accordingly.
2
NOPAT is calculated as annual EBIT less tax (tax includes annual tax expense and movements in deferred tax over the year as a proxy for cash tax paid). Invested capital is calculated as the average of the opening and closing balance of:
net working capital (adjusted to remove current borrowings, current net derivatives and excess cash above $50m) + non-current assets (adjusted to remove non-current derivatives). The ROIC calculation includes the after-tax movement in the AGS
provision over time. In FY25 this amounted to a $71m benefit in the NOPAT figure.
3
ROIC average is calculated as NOPAT (4-year average) / Average IC (4-year average).
4
ROIC (FY) is calculated as Annual NOPAT (FY) / Average IC (FY).
434
309
110
285
6
0
473
Sources
13
361
43
Uses
1,0171,017
Cash Used
Debt drawdown
OpFCF
Dividend
re-invested (DRP)
Sale of asset
Strategic investments / acquisitions
Growth investment
Dividends paid
Financing costs
Realised losses on market derivatives
0
1
2
3
4
5
8
9
3.6%
3.7%
3.7%
3.3%
3.7%
4.9%
ROIC (average)
3
ROIC (FY)
4
475
Net operating profit after taxes (NOPAT) / Invested capital (IC)
2
Average IC
($m)
4,575
4,482
4,518
4,874
5,349
5,670
FY20FY21FY22FY23FY24FY25

26
Growth capital expenditure
1
Excludes ~$1m of development capex that has been approved to advance Manawa projects in FY26.
2
Total under current board approvals.
3
For Te Mihi Stage 2, the board approved an additional $49m contingency (over and above the contingency amount already included in the expected and approved total construction cost of $712m) to account for a scenario where a broader range of
risks materialise and to ensure prudent balance sheet management. If called on, this would take the total cost to $761m.
4
Relates primarily to Western coil tube drilling and deployment of demand flex technology.
5
Relates to Te Mihi Stage 2 and Glenbrook-Ohurua BESS development.
6
Excludes pre-FID development expenses for solar which are captured within receivables.
Growth capital expenditure – cash basis ($m)¹
Up to
30 June 2024
12 months ended
30 June 2025
Remaining under
current approvals
Total²
Tauhara$852m$53m$26m$931m
Te Huka 3$246m$47m$12m$305m
Te Mihi Stage 2$57m$144m$511m$712m
3
Wind$13m$8m$5m$26m
Glenbrook-Ohurua BESS$5m$87m$71m$163m
Other
4
$17m$2m$3m$23m
Capitalised interest$173m$23m$70m
5
$266m
Total$1,363m$363m$697m$2,425m
Contact’s FY25 growth investment demonstrates progress in the strategic execution of its renewable
development pipeline
•Construction commenced in FY25 on three major renewable projects: the
Glenbrook-Ohurua Battery Energy Storage System (BESS), the Kōwhai
Park solar farm, and the Te Mihi Stage 2 geothermal plant.
•The totals shown reflect board-approved funding and include pre-FID sunk
costs of $66 million for Te Mihi Stage 2 geothermal and $5 million for the
Glenbrook-Ohurua BESS.
•Construction of the Tauhara and Te Huka 3 geothermal plants is now
complete. Remaining spend on Tauhara relates to planned works during its
first statutory outage in November 2025. For Te Huka 3, the remaining
spend reflects final milestone payments due post-completion.
•Contact does not currently have any wind projects under construction. The
reported wind development spend reflects pre-FID activity only.
•For major growth projects, Contact capitalises interest from the point of
FID—or from the commencement of significant pre-FID works—through to
commissioning. The capitalisation rate reflects the average interest rate
across the portfolio.
•Contact’s investment in the Kōwhai Park solar farm is accounted for as an
investment in joint ventures and associates, and is therefore excluded from
growth capital expenditure.
Up to
30 June 2024
12 months ended
30 June 2025
Remaining under
current approvals
Total²
Solar
6
--$37m$37m
C0
2
$2m$5m$1m$7m
Forestry$44m$39m$1m$84m
Total$45m$43m$39m$128m
Investment in joint ventures and associates ($m)
FY25 results: Cash flow

27
Approach and FY25 highlights
•Contact’s capital management strategy is
anchored to maintaining an investment grade
credit rating, which is supported by a net debt
to EBITDAF sustainably below 3.0x. At FY25
year-end, the point estimate of net debt to
EBITDAF was 2.3x.
•During FY25, Contact issued a NZ$250 million
Capital Bond and a A$400 million Australian
Medium Term Note (AMTN). Both instruments
were certified Green under the Climate Bonds
Initiative framework and support the funding of
Contact’s renewable development pipeline.
Looking ahead
•Following the completion of the Manawa
acquisition on 11 July 2025, Contact raised
NZ$900 million in new bank debt. This was
used to repay Manawa’s existing bonds
(NZ$388 million), settle bank facilities, and fund
the cash consideration paid to Manawa
shareholders.
•It is expected that the Manawa acquisition will
increase net debt to EBITDAF in the near term
and it may temporarily lift above 3.0x. However,
it is expected to return below the threshold as
the benefits of the acquisition are realised.
Contact’s diverse funding sources enable continued renewable build
Closing net debt ($m)
Face value of borrowings less cash
Interest rate (%)
Weighted average gross interest
2
on average borrowings
Net debt to EBITDAF (x)
Includes S&P adjustments
3
Borrowing maturities ($m)
Average tenor of 7.7 years as at 30 June 2025
Supportive balance sheet
1
Includes $87m (FY24) and $0m (FY25) of collateral held on deposit for margin calls associated with the trading of electricity price derivatives on the ASX. Includes $180m of commercial paper (FY25) not shown in borrowings breakdown (right).
2
Gross interest includes all interest on borrowings, bank commitment fees and deferred financing costs. Unwind of leases, provisions and capitalised interest not included.
3
Illustrated here on a point basis based on expected S&P adjustments. See breakdown of S&P approach on slide 51.
774
1,025
1,474
1,831
2,314
-514
22
-44
FY20
21
-150
FY21
25
-168
FY22
49
-140
FY23
47
-229
FY24
50
FY25
1
1,014
645
882
1,383
1,649
1,850
1,036
Lease obligationsBorrowingsCash on hand
67
434
435
225
250
135
150
300
250
350
350
7
FY26
7
FY27
22
4
FY28FY29FY30FY31FY32FY52FY55
142
157
625
717
Undrawn bank facilities
Domestic bonds
USPP
NEXI
Capital bonds
AMTN
2.4
1.4
1.8
2.6
2.7
2.3
FY20FY21FY22FY23FY24FY25
974
892
5.2%
FY20
5.2%
FY21
5.4%
FY22
5.8%
FY23
6.1%
FY24
5.8%
FY25
1,029
1,310
1,727
1,973
Average gross interestAverage gross debt
FY25 results: Key balance sheet metrics
1

28
Dividend for FY25 of 39 cents per share
•The final dividend of 23 cents per share is imputed up to 57% or 13 cents per share for qualifying shareholders.
•This takes the total FY25 dividend declared to 39 cents per share, representing a pay-out of 82% of FY25 operating
free cash flow and 101% of the average operating free cash flow over the preceding 4 financial years (FY21-FY24).
•The record date is 26 August 2025; payment date is 24 September 2025.
•The NZD / AUD exchange rate used for the payment of Australian dollar dividends will be set on
3 September 2025.
Dividend per share for FY25 39cps, up 5%
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 final 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 27 August 2025 to confirm participation in the plan.
•The trading period for setting the price for the DRP is 25 August 2025 to 29 August 2025. The DRP strike price
will be announced: 1 September 2025.
Ordinary dividends ($m)
Declared
Final dividend
Interim dividend
% pay-out of annual operating free cash flow
3535
35
37
39
83%
97%
68%82%
Operating free cash flow
Average operating free cash flow for the preceding four financial years
Contact’s dividend policy is to pay dividends of 80-100% of average operating free cash flow of
the preceding four years. As the historic measure will not capture the operating free cash flow
contribution from Manawa within the history, the Board will apply discretion in the first few years
post-acquisition, if the measure is temporarily above 100%, so that it is not constrained in
delivering the expected DPS uplift. This has been the approach taken in FY25. If the shares
issued as consideration for Manawa are excluded, the FY25 dividend declared would represent a
pay-out of 72% of FY25 operating free cash flow and 89% of the preceding 4-year average.
309
247
FY21
326
261
FY22
333
266
82%
FY23
318
256
92%
FY24
352
282
101%
FY25
371330
282
➢Annual operating
free cash flow
100%
80%
Dividend level
as a % of preceeding
4yr operating fcf
163
164
165
181
227
109
109
109
110
128
FY21FY22FY23FY24FY25
272
273
274
291
355
cps
73%
424434
1
All dividend decisions are a matter for the Board at the conclusion of each reporting period. These align to the dividend policy and are dependent
on business and market conditions when each payment decision is made.
Dividend expectations
•Contact indicated that it expects to lift the total dividend in FY26 to 40cps and between 41 and 42cps in FY27.
1

‒On this basis, dividends in FY26-FY27 are expected to be imputed up to ~80%.
•Reliable ordinary dividends are expected to increase over time with growth in operating free cash flow.
Reflects 101% of the average operating free cash flow for the preceding four years

29
Normalised and expected FY26 EBITDAF $980m
1
Before Manawa transaction and integration costs and assuming mean hydrology and wind conditions
Strategic fixed price3,960GWh$95/MWh$376m
CFDs1,700GWh$155/MWh$264m
C&I1,750GWh$165/MWh$289m
Retail3,825GWh$164/MWh$627m
Other income
4
$100m
$1,656m
Hydro mean5,750GWh$0/MWh-$0m
Geothermal average4,950GWh$4/MWh-$20m
Thermal275GWh$215/MWh
5
-$59m
Renewable PPAs830GWh$100/MWh=-$83m
Acquired200GWhx$260/MWh
6
=-$52m
-$214m
Length
7
$139mTransmission/Storage-$90m
Location losses
8
-$140mOpex underlying (including in-year synergies)-$370m
Opex - Integration & transaction costs -$35m
Total Opex-$405m
Total$-1mTotal -$495m
2. All volumes are at the Grid Exit Point (GXP).
3. Net price is equal to tariff less pass-through costs (network, meters and levies) /MWh.
4. Steam sales, retail gas gross margin, telco gross margin and other income.
ASSUMPTIONS FOR NORMALISED EARNINGS
5. Gas price of $16/GJ, carbon price of $80/unit and thermal portfolio heat rate (10.5GJ/MWh).
6. Acquired generation price includes premiums paid for HFO (operational from 1 Jan 2026), and
NZAS demand response.
7. Length of 770GWh p.a. assumed.
8. Locational losses of 6.5% on spot purchases and settlement of
CFDs sold at a wholesale price of $180/MWh.
* Fuel is natural gas and carbon costs.
1,046
654
Channel choices maximise
long term value
2
1
Net price
3
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
x
x
x
x
x
x
x
=
=
=
=
=
=
1,535
215
3,825
3,960
CFDs
C&I
Retail
Strategic fixed
$155/
MWh
$165/
MWh
$164/
MWh**
ContractedUncontracted
1,656
-214
-90
-370
-1
-35
945
x
153
150
160
123
219219219
247247247
142
133
140
111
140
183183
223
160
147
Aug-
25
Sep-
25
Oct-
25
Nov-
25
Dec-
25
160
Jan-
26
Feb-
26
Mar-
26
Apr-
26
May-
26
Jun-
26
ASX Futures $/MWh
At 6 Aug 2025
$95/
MWh
OTA monthly
OTA Quarterly
BEN Monthly
BEN Quarterly
1. Normalised and expected EBITDAF assumes mean hydrology and wind for the year and assumes planned asset availability / capacity i.e. adjusts for planned in-year outages (e.g. geothermal statutory outages, hydro refurbishments).

=
Trading delivers value to largely
offset locational losses
5
Digitalisation & continuous
improvement optimise fixed costs
6
Reported basis
Includes $35m
integration and
transaction costs
Opex (underlying)
Opex (integration
and transaction)
$m
** Retail volume contracted. Competitive risk remains on pricing achieved.Note: All figures are subject to rounding.
GWh:

30
Update on
Manawa and
strategic
delivery

31
31
Recap: A strategically compelling acquisition
Combined portfolio will see mean renewable
generation of more than 11TWh
2
with ~98%
renewable output
2
, accelerating Contact’s
strategy to grow renewable generation while
decarbonising its portfolio.
1
Geographically diversified hydro schemes are
complementary, enhancing portfolio resilience
and the volume of fixed price supply agreements
able to be placed into the market.
1
2
Hydro flexibility is expected to provide firming to
expedite intermittent renewable development.
3
Highest value options can be advanced from an
attractive and diversified combined
development pipeline, supported by Contact &
Manawa’s renewable development execution
capabilities.
4
1
When compared to the volume that can be supported by Contact’s and Manawa’s standalone hydro portfolios.
2
Based on long term average hydrological conditions and an expectation of 200GWh to 300GWh of gas generation through the Stratford peakers following the planned closure of the Taranaki Combined Cycle gas plant in late 2025. Excludes
any short-term acquired generation purchases e.g. fuel replacement via ASX which will reflect the renewable mix of the market.
0.6
0.8
1.0
1.2
1.4
123456789101112
Seasonal shape
Monthly averages (2007-2023)
Manawa
Contact
Output relative to average (x)
0.8
0.9
1.0
1.1
1.2
1.3
200720092011201320152017201920212023
Manawa
Contact
Volatility and generation shape over time
Output relative to average (x)
Average
Average
JanFebMarJunJulSepOctNovDecAprMayAug

32
Delivering on the promise of the Manawa acquisition
Contact is well-positioned to deliver the benefits of the Manawa acquisition, backed by market tailwinds and a
proven integration approach
Re-cap: Expected benefits on transaction announcement (EBITDAF)
1

Status
Key changes
Cost
synergies

$23m – $28m
100% within 18-24 months
Generation
normalisation

~$11m
MCY, PPA & C&I
contract rollover

~$21m
Expected portfolio
benefits

$10m - 20m
Embedded value – Future Manawa standalone earnings potential
✓
On track
✓
On track
✓
On track
✓
On track
Continued integration plan
refinement has underpinned
confidence in cost synergies
➢Targeting $25m - $28m
operating cost reduction
➢Targeting $26m - $29m cash
opex and financing cost
synergies
➢100% within 12-18 months
(exit run-rate)
Key milestones met in Manawa
asset refurbishment programme
➢Matahina upgrade completed
in FY25 (17GWh mean annual
uplift)
➢On track to achieve mean
annual hydro generation of
1,991GWh from FY28
Contact’s view of long-term
wholesale prices remains
$115 to $125/MWh
2

➢Benefit of ~$21m is a long-
term estimate i.e. no change
➢Near-term upside from ASX
electricity futures uplift since
announcement
Emerging market trends
support future quantified and
non-quantified portfolio
benefits
Widening of winter / summer
ASX electricity futures pricing
gap since announcement
(up >20%)
➢Value shift to flexibility
1
Expected EBITDAF benefits as presented at announcement on 11
th
September 2024 – Shown with reference to Manawa’s FY24 EBITDAF (March year end).
2
Real 2025. This is a through-the-cycle measure in a balanced market. Prices achieved are a function of the market at a point in time.

33
ASX Futures (Quarterly, base period, OTA)
3
$/MWh
Increase in electricity futures prices expected to provide
higher near-term hedge repricing benefits
1
Represents incremental annual output delivered by the programme. Assumes mean hydro and a 2021 baseline.
2
Phased uplift to occur from FY26.
Winter 2026 and winter 2027 ASX futures
up >20% vs. announcement
80
100
120
140
160
180
200
220
240
Q1Q2Q3Q4Q1Q2Q3Q4Q1Q2Q3Q4
1,576
457
1,079
825
576
326
250
869
748
1,001
1,251
1,500
1,750
500
0
500
1,000
1,500
2,000
FY26FY27FY28FY29FY30FY31
76
FY32
Roll-off (cumulative)ASX-linked
4
Fixed price (set 2021) + CPI
GWh
+21%
+22%
Key milestones met in Manawa’s asset refurbishment
programme: On track for 1,991GWh p.a. mean output from FY28
Project StatusUplift (GWh)
1
Branch
Completed
10
Matahina
Completed
17
Waipori
Completed
-
Cobb
Completed
-
Arnold
Completed
-
Various
Completed
20
Highbank
On track – FY27
8
Coleridge
On track – FY28
2
23
Total
78
47
12
14
59
72
78
0
20
40
60
80
FY22-FY25FY26FY27
6
FY28
Hydro uplift over time – approved projects
1

(30 June year end)
Hydro improvement project status
Asset upgrades and market tailwinds building
confidence
Current
At announcement
Completed (cumulative)
On track
Mercury hedge volume
(30 June year end)
3
ASX NZ Electricity Otahuhu base quarter futures pricing as at 30 July 2025.
4
Pricing linked to historic rolling ASX prices from 1 October 2026.
Volume is winter-weighted
(60% / 40%; winter / summer)
CY 2026CY 2027CY 2028
GWh

34
Cost synergies on track
Opex reduction target: In-year benefit
$m
FY26FY27
Opex reduction target: Exit run-rate
$m
FY26FY27FY26FY27
Integration costs (opex)
1
$m
Integration Management Office (IMO) established.....
A well resourced integration management programme is in place
6
Integration management
workstreams
9
Functional
workstreams
~70
Initiatives
Executive sponsorship for each workstream and initiative
IMO accountabilities:
▪Ensure a smooth transition for teams, systems, and operations.
▪Achieve ~70% of targeted cost reductions within the first six months
(exit run-rate basis).
▪Deliver the full value of the acquisition, including cost synergies.
▪Guide the organisation through its transition to the future operating model.
.....with granular plans firming up targets for cost synergies
Cost reduction targets confirmed (all shown pre-tax)
Opex reduction target at
announcement:
Opex reduction target
now:
$23m - $28m
100% within 18-24
months post completion
(exit run-rate)
100% within 12-18
months post completion
(exit run-rate)
$26m - $29m
Cash opex and financing
cost synergy target:
100% within 12-18
months post-completion
(exit run-rate)
33 – 37
20 – 25
10 – 15
10 – 20
23 – 27
Expected combined operating costs FY26
$m
$m
Opex reduction (in-year benefit)10 – 20
Less: Integration costs within opex
1
(20 – 25)
Less: Transaction costs within opex (13)
Total operating costs(400 – 410)
1
Approved integration costs (both opex and capex) total $45m over FY25 to FY27 ($7m has been incurred in FY25) with an additional $9m contingency. The ultimate allocation between opex and capex is dependent on accounting treatment and is
yet to be confirmed.
$25m - $28m
22 – 25
25 – 28

35
Upside from portfolio combination benefits to come
Since the acquisition announcement, updated New Zealand
gas reserve data shows a decline of more than 20% in forecast
production for each year through to 2030, relative to 2024
estimates.
1
Limited gas availability and rising costs have
pushed the marginal cost of thermal generation above
$200/MWh.
Material downgrade to gas
field reserves
Supported by market trends... ... which are expected to grow the portfolio combination benefits
Winter Summer Price
Separation Widening
Value shift to flexibility
While average prices continue to reflect long-run economics,
ASX Futures show winter prices rising significantly faster
than summer prices. This trend is driven by the need to
recover higher thermal fuel costs and the growing share of
must-run renewables in the market. Futures for winter 2026
and 2027 are now up >20% compared to levels at the time
of the acquisition announcement.
We expect market value to increasingly favour operators of
flexible, intra-day assets and those with fuel storage—rather
than intermittent renewable generators.
Combined inflow
characteristics
Increasing
importance of
flexibility
More efficient
participation in spot
market
How is it
captured?
Quantification
(2025, Real, $m)
13
•Portfolio diversification reduces risk.
•Increased fixed-price sales enhance revenue certainty.
•Greater flexibility in managing stored fuel (eg AGS and Hydro).
•Reduced generation costs through avoided gas use.
•Lower spend on risk management products (e.g. HFO).
•Improved arbitrage margins from battery storage (BESS).
•Higher generation-weighted average price (GWAP).
•Increasing GWAP:TWAP
ratio for key flexible
assets over time.
Benefits quantified
and included in
acquisition
evaluation
✓
?
Not included in acquisition
evaluation. Benefits
present future upside
potential
•$10m - $20m, mid-point $15m targeted FY27
2
•$5m targeted FY26
2
•n/a
Focus on capturing the benefits of increased generation flexibility, increased access to renewable winter energy
and reducing hydrology risk
•Initial coordination in place from Day 1 through existing communications and
processes.
•Gradual integration of dispatch operations across both portfolios.
•Enhanced real-time decision-making to optimise dispatch across all assets.
Steps to
achieve
1
Source: MBIE 2P reserves data published 5 June 2025; Contact analysis.
2
This is a through-the-cycle measure. Actual result will be impacted by hydrology, fuel and other market conditions.
•Unlock further flexibility and
improve monetisation with
improvedtrading of assets.
2

36
Combined portfolio 98% renewable from FY26 (mean wind and hydro)
1
Final commissioning activities were ongoing at the illustrated online dates for each of Tauhara and Te Huka 3. Those commissioning activities were completed in FY25.
2
The uplift of 78GWh p.a. is on a 2021 base and assumes mean hydrology. As at 30 June 2025, asset refurbishments have been completed delivering 47GWh p.a. of this uplift, with work continuing on the 31GWh p.a. remaining. See slide 33.
3
FY25 generation figures reflect actual volumes in FY25. FY26 and FY28 volumes assume mean hydro and wind generation and account for planned hydro outages (refurbishments) and the geothermal statutory outage schedule. See slide 47.
4
Other geothermal volume excludes geothermal PPA purchases due to the near-term completion of the contract (December 2026).
Summary of renewable projectsdelivered and underconstruction
Expectedgeneration(indicative):
Indicative output by source over time (TWh)
3
Existing plant and committed projects only:
1.0
0.6
1.3
0.9
2.3
1.4
2.6
3.3
1.1
5.8
FY25
0.3
FY26
8.9
11.6
+30%
100MW/200MWh
Glenbrook-Ohurua BESS
Other renewable
electricity assets
available by FY28
Wind (PPA)
Tauhara
online
1
TeHuka3
online
1
TeMihi Stage2
(0.8TWh)
Wairakei Partial closure
(-0.6TWh)
Glenbrook-
Ohurua
BESS
(100MW)
Roxburgh hydro
(45GWh p.a. mean uplift)
KōwhaiPark
Solar
(0.3TWh)
2024202520262027
Calendaryear
Delivered
Under
construction
Manawa hydro asset refurbishments
(78GWh p.a. mean uplift)
2
Renewable output:
88%~98%
Annual mean renewables to support electricity sales to be above 12TWh per annum from FY28
0.6
2.2
2.5
5.9
0.2
0.2
0.5
FY28
12.1
~98%
Wairakei station
Te Mihi
Other geothermal
4
Solar
Hydro
Thermal
Chart excludes short-term
acquired generation
purchases e.g. fuel
replacement via ASX which
will reflect the renewable
mix of the market

37
Development prioritised as the market requires
Grid connection and transmission
Ease of consent; Ease of construction
Quality of resource; Capacity factors
Development options across Contact and Manawa’s integrated pipeline will be prioritised and advanced based on
key strategic evaluation criteria and guiding capital allocation principles
Location and shape vs. demand
Portfolio diversification and fit
Relative cost; Funding model
Key strategic evaluation criteria for renewable projects
Investtodelivervalueaccretivegrowth
•Returnsimprovedthroughprioritisationofnon-equityfunding.
•Projectsrankedconsideringreturnsavailableandoverallportfolioimplications.
•Allocate capital to strategic priorities, with an ability to scale down in downside scenarios.
Optimise existing operations and manage risk
•Reducecarbonexposure and manage marketvolatilityduringthethermaltransition.
•Disciplinedapproachtosustainingcapitalspend.
−Efficient deployment of stay-in-business capital expenditure.
•Strong operating cash flow.
Continuetoattractcapital
•Delivercompetitiveshareholderreturnsincludingdividendcommitment.
−Reliable ordinary dividends that increase in line with growth in cash flow.
−Pay-out ratio of 80-100% of average operating free cash-flow over the preceding 4 years.
•Balancesheetstrength with investment grade credit metrics through the cycle.
−Target BBB <3x net debt to EBITDAF.
−If temporarily above, always have clear plan to restore metrics.
Recap: Contact’s guiding capital allocation principles
Considering supportive market conditions and a broad range of attractive
projects post Manawa acquisition, we will prioritise investments to grow
shareholder value and distributions
Strategic evaluation criteria are used to prioritise development options
that will offer the most attractive returns on investment; prioritised
projects compete under our capital allocation framework

38
Project
Capacity
(MW)
1
Estimated
output (GWh)
Expected
online date
Earliest
available
investment
timing /
decision
2
Project status
Land
secured
Consent
lodged
Consented
Under
construction
Contact
Committed
Kōwhai Park Solar168275Q2 CY2026
Glenbrook-Ohurua BESS100n/aQ1 CY2026
Te Mihi Stage 2101840Q3 CY2027
Assessing
Glorit Solar170280FY26
Glenbrook BESS 200
3
200
3
n/aFY26
Southland Wind
4
3261,210FY27
Strafford BESS
5
100n/aFY27
Stratford Solar180300FY27
Other solar7001,155Various
Other wind6852,470Various
Other geothermal
6
TBC~1TWh>FY28
ManawaAssessing
Argyle 1 & 2
90177FY26
Kaipara
113190FY27
Huriwaka
300890FY27
Hawke's Bay Airport
4580FY27
Kaihiku (JV)
7
3001,060FY27
Hapuakohe
230710FY28
Mackenzie Basin
283540FY28
Ototoka
150530FY29
Marlborough Wind
100330FY29
Development options across a diverse combined pipeline of >10TWh
An attractive and diversified development pipeline
1.Capacity for solar projects is shown as MWp.
2.All available FID timings are to be confirmed.
3.Indicative sizing at FID. Consent application filed for 400MW
new capacity, providing future optionality.
4.Based on 6MW turbines. Turbine size is to be confirmed.
5.Capacity of 100MW consented. Preparing to seek consent
for additional capacity.
6.Reflects uplift in output available from Tauhara Stage 2 and
Te Mihi Stage 3 from consented fluid take.
7.Kaihiku is a 50:50 JV with 300MW total capacity.
Solar options
Wind options
Land access secured
Consenting underway
Consented
7TWh
3TWh
Combined solar and wind pipeline
options of >10TWh

39
Our operational plan for the next 12 months
FY26
Achieve FID for CO
2

Glenbrook-Ohurua BESS online Q1 CY2026
Kōwhai Park solar online Q2 CY2026
Te Mihi Stage 2 geothermal on track for
online Q3 CY2027
Close TCC gas generation plant late CY 2025
Scope 1 & 2 emissions <650ktCO
2
e
2
Multi-product customers >156k (up from 149k)
Cost to serve <$116/connection
3
Grow renewable
development
Decarbonise
our portfolio
Create outstanding
customer
experiences
Strategic theme
Grow
Demand
Subject to market conditions and
obtaining consents, achieve FID on:
▪Solar (e.g. Glorit, Argyle); and/or
▪Glenbrook 200 BESS
New demand facilitated since FY21 to reach >250MW
1
At least 50% of new demand contracted in-year structured
with favourable shape (considering load and generation)
Sustained New Zealand leadership position in
the Asia Pacific DJSI
Next update on strategy will be provided at Contact’s November 2025 Capital Markets Day
Manawa
integration
In-year benefits target:
▪Opex reduction $10m to $20m
▪Portfolio benefits $5m
4
Targeting net price up by ~2%
Exit run-rate benefits target:
▪Opex reduction $22m to $25m
▪Portfolio benefits $10m to $20m
4
Consents lodged on at
least 2 renewable
development projects
1
Cumulative measure (~230MW as at 30 June 2025). Shown on a total contracted basis.
2
Assumes mean hydrological conditions.
3
Excludes customer acquisition costs.
4
This is a through-the-cycle measure. Actual result will be impacted by hydrology, fuel and other market conditions.

40
Questions

41
Supporting
materials

42
Guidance topics
FY25 guidanceFY25 resultFY26 guidanceFY26 Guidance Commentary
Stay in business (SIB) capex (cash)
$120-130m$110m$175m - $190m
SIB capital expenditure BAU
$77m - $87m$71m$115m - $125mAt the mid-point ~$5m higher than long-run expectations due to consenting.
SIB accelerated programme
~$40m$36m$12m - $13m Close-out of Contact’s $150m accelerated capex programme announced 2021.
SIB capital expenditure Wairakei
$2m - $3m$3m$20m - $25mWairakei extension costs.
SIB capital expenditure enhancements and integration
nana$23m - $27mGeothermal wells (~$8m), Manawa hydro refurbishment (~$12m) and integration.
Growth capital expenditure (cash)
1
$450m - $550m$363m$390m - $400mGrowth capital for Tauhara, Te Huka 3, Te Mihi Stage 2, Wind and BESS projects.
Depreciation and amortisation
$275m - $285m$273m$280m - $290m
Reflects useful life changes on thermal assets, introduction of Tauhara and Te
Huka 3 as well as Manawa expected depreciation.
Net interest (accounting)
$105m - $115m$100m $145m - $165m
Reduction in capitalisation of interest with Tauhara commissioning. Higher interest
rate environment and increased borrowings with Manawa acquisition.
Cash interest (in operating cash flow)
$85m - $95m$80m$135m - $155m
Cash taxation
$105m - $115m$106m$130m - $140m
FY26 provisional payments based on FY24 results and higher final tax payment
relating to FY25. Includes estimated Manawa tax payments.
Realised (gains) / losses on market derivates not in a
hedge relationship
$15m - $20m$13m$10m - $15mIncluding (gains) / losses on ASX market making.
Corporate costs - ex Manawa
$54m$55m$55m
Reflects Contact corporate costs only. Manawa corporate costs are all allocated to
wholesale. As integration progresses, allocations may be updated.
Corporate costs - Manawa integration and transaction
$20m$18m$30m - $40mNon-recurring costs relating to the Manawa acquisition.
Target ordinary dividend per share
39 cps39 cps40 cpsIncrease in the ordinary dividend to reflect benefits of the Manawa acquisition
Operating cash flow conversion
50%55%
2
~50%
Higher interest costs as investments come online (meaning lower capitalised
interest) and reflecting Manawa debt. Working capital to support HFO.
1
Growth capital expenditure includes capitalised interest.
2
Based on $774m underlying EBITDAF.

43
Strategic fixed price1,900GWh$80/MWh $152m
CFDs1,770GWh$154/MWh$273m
C&I1,300GWh$150/MWh$195m
Retail3,800GWh$154/MWh$585m
Other income³$47m
$1,252m
Hydro3,900GWh$0/MWh-$0m
Geothermal4,620GWh$4/MWh-$19m
Thermal⁴350GWh$130/MWh
4
-$46m
Acquired350GWh$215/MWh-$75m
-$139m
Length⁵$86mTransmission/Storage-$71m
Location losses⁶-$85mOperating expenses-$272m
Total$1mTotal-$343m
FY25 assumptions that deliver expected & normalised EBITDAF of $770m over a financial year
EBITDAF guidance reconciliation to actual FY25
Hydrology & Asset
availability optimise generation
3
4
Total
x
=
Access to and price of fuel* drives
financials & risk position
Increased market channel price
Normalised & Expected
Lower renewables
Other income
Actual FY25 EBITDAF (underlying)
Hydro generation below mean (-603GWh).
Impact calculated at thermal SRMC
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
=
=
=
=
=
=
=
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, telco gross margin and other income.
4.Gas price of $8.2/GJ, carbon price of $80/unit and thermal portfolio heat rate
(10GJ/MWh).
5.Length of 450GWh assumed.
6.Locational losses of 5.1% on spot purchases and settlement of CFDs.
sold at a wholesale price of $190/MWh.
Fixed costs
LCE rebates ($11.5m) and AGS provision unwind partly
offset by opex increase
Normalised and expected EBITDAF assumptions
FY25 results
With reconciliation to actual performance
x
Increased long–term channel price
Retail ($160/MWh) & Strategic fixed price sales ($85/MWh) prices
higher than expectation (the latter due to NZAS demand response)
Higher CFD price ($205/MWh) with tight market
conditions and thermal-backed CFD sales
Gas, carbon, acquired generation price
Gas prices were materially higher in the period ($15/GJ)
Demand response payments to NZAS included
Volumes above expected; lower than expected location loses
Net volume impact
Risk management sales premiums and expected
losses from distressed gas sales not realised
Manawa transaction and integration costs
EBITDAF pre Manawa-related costs
*
Fuel is natural gas and carbon costs.
136
38
102
17
17
18
4
15
770
792
774

44
57
76
53
939
-258
-265
-291
-315
-346
-76
-85
-56
-74
-80
-230
-185
-94
-269
-326
1,069
48
FY21
1,023
FY22FY23
1,269
FY24
1,476
50
FY25
Electricity sales margin
Other gross margin
Fixed operating costs
Location losses
Variable fuel costs
553
546
573
663
774
Operating earnings (EBITDAF)
108
106
115
127
136
3.61
1.33
FY21
3.69
1.39
FY22
3.73
1.42
FY23
3.80
1.22
FY24
3.69
1.73
FY25
4.94
5.08
5.14
5.02
5.42
RetailStrategic fixed-price
101
117
126
200
1.67
0.55
FY21
1.13
0.39
FY22
0.52
0.15
FY23
116
1.62
0.59
FY24
1.09
0.46
FY25
2.23
1.52
0.67
2.20
1.55
ThermalAcquired
Electricity sales
Variable fuel costs
11111
3.70
3.11
FY21
3.94
3.28
FY22
3.92
3.19
FY23
3.63
3.39
FY24
3.30
4.54
FY25
6.81
7.22
7.10
7.02
7.84
HydroGeothermal
(i) Renewables
(ii) Thermal and acquired
131
133133
150
186
1.23
1.94
0.93
FY21
0.94
2.10
0.63
FY22
1.10
1.44
0.09
FY23
1.13
2.57
0.51
FY24
1.17
2.30
0.51
FY25
4.10
3.66
2.63
4.21
3.97
Commercial and IndustrialCFDsSpot sales
(i) Long-term channels
(ii) Market channels
Price
($/MWh)
Volume
(TWh)
Price
($/MWh)
Volume
(TWh)
Fuel cost
($/MWh)
Volume
(TWh)
Fuel cost
($/MWh)
Volume
(TWh)
Integrated portfolio performance
Continuing operations ($m)
1
EBITDAF
1
2
1
2
1
Refer to slide 50 for a definition and reconciliation of EBITDAF. All EBITDAF figures are underlying i.e. excluding the impacts of the ($113m) AGS onerous contract provision expense in FY23, a $12m net movement in the AGS provision in FY24, and a
release of the AGS provision of $98m in FY25.
118117121
137
158
9.040
8.739
7.772
9.232
9.390
Price
($/MWh)
Volume
(TWh)
Historic performance

45
Greenhouse gas emissions
Carbon reporting
1
Contact’s swaption with Genesis Energy ended 31 December 2022 and was not called during FY23.
2

All Science-based targets are on a calendar year basis.
IndicatorUnitTargetFY21FY22FY23FY24FY25
Direct GHG emissions (Scope 1)tC02e
45% reduction of 2018
Scope 1 and 2
emissions by 2026
(Absolute emissions
reduction target)
2
1,044,744786,842526,621947,491740,468
-Stationary combustiontC02e1,044,537786,544526,282947,131739,945
-Mobile combustiontC02e178297307332409
-Fugitive emissionstC02e2913228114
Indirect GHG emissions (Scope 2)tC02e1,303
1,3991,9579751,183
Sub-total Scope 1 and 2tC02e647,4431,046,047788,241528,579948,466741,651
Indirect GHG emissions (Scope 3)tC02e259,118555,035394,784273,673265,034369,583
-Category 1 – Purchased goods and servicestC02e
30% reduction of 2018
Scope 3 GHG
emissions from use of
sold products by 2026
2
16,699
6,3716,1976,5228,799
-Category 2 – Capital goodstC02e41,72657,87688,26679,18587,203
-Category 3 – Fuel and energy
1
tC02e330,207149,7431,0505,1308,006
-Category 4 – Upstream distribution and transportationtC02e27444108254205
-Category 5 – WastetC02e149108475869
-Category 6 – Business traveltC02e2635671,2741,6011,081
-Category 7 – Employee commutingtC02e306832965927956
-Category 11 – Use of sold productstC02e165,259178,554175,603170,929250,612
-Category 13 – Downstream leased assetstC02e399289164429339
-Category 14 – InvestmentstC02e----12,313
Total Scope 1, 2 and 3 emissionstC02e906,5611,601,0821,183,025802,2521,213,5001,111,235

46
Contact generation output sold to the national grid (GWh)
Generation and sales position
3,256
3,333
3,114
3,283
3,185
3,388
4,543
4,231
3,752
3,698
3,940
3,919
3,628
3,297
1,421
1,360
1,592
1,046
1,620
1,088
FY19FY20FY21FY22
439
FY23FY24FY25
Thermal
generation
Hydro
generation
Geothermal
generation
8,908
8,445
8,404
8,269
7,543
8,636
8,928
Operational data
Renewable % of
own generation
sold to grid
84%84%
81%
88%
87%
94%81%
Geothermal generation (GWh)
FY25 geothermal generation was ~1.2TWh higher than FY24. Generation from the new Tauhara and
Te Huka 3 plants (1.5TWh) was partially offset by statutory outages at Te Mihi, Wairakei and Ohaaki.
1,382
1,415
1,240
1,386
1,380
991
1,045
1,081
1,055
998
1,405
1,255
388
335
339
331
308
1,064
1,287
310
340
299
322
323
274
986
186
198
155
189
176
316
300
203
277
210
FY19FY20FY21FY22FY23
127
FY24
229
FY25
3,257
3,333
3,114
3,283
3,185
3,388
4,543
Hydro generation (GWh)
FY25 was marked by two periods of historically low inflows (July – August 2024 and January – April 2025). The
result of these conditions meant total inflows for the year were 701GWh below FY24 volumes.
103
4,786
69
4,069
3,959
75
4,276
-59
3,904
-51
5,450
-101
3,681
-975
-1,606
-148
FY19FY20
-275
FY21
-78
FY22
75
FY23
-230
FY24
-459
FY25
4,231
3,752
3,698
3,940
3,919
3,628
3,297
Inflows stored include uncontrolled storage lakes
Inflows
Inflows
stored
Spill
Thermal generation (GWh)
1,013
871
1,126
673
164
1,395
692
207
291
234
179
148
223
378
195
195
213
190
125
78
5
83
FY19
3
79
FY20
18
81
FY21
4
81
FY22
2
FY23
1
FY24
18
FY25
1,503
1,439
1,673
1,127
517
1,620
1,088
Although down significantly on FY24, thermal generation volumes were materially higher than mean
expected volumes due to dry conditions in winter 2024 and Jan to April 2025.
Te Huka
Ohaaki
Poihipi
Wairakei
Te Mihi
Tauhara
Te Huka 3
Whirinaki
Te Rapa - direct
Te Rapa - spot
Stratford Peakers
TCC

47
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
20
40
60
80
100
0
99%
88
FY19
100%
90
FY20
98%
87
FY21
100%
89
98%
89
FY23
100%
91
FY24
95%
87
FY25FY22
-5%
31.4
31.1
30.5
31.0
30.4
29.2
29.7
FY19FY20FY21FY22FY23FY24FY25
+2%
Geothermal fuel performance
Taranaki combined cycle (TCC)
Hydro
Geothermal
1
Stratford Peakers
Plant availability
Availability Factor calculation includes all station outages (Planned, Maintenance, Forced) but does not consider plant deratings.
1
Reduction in geothermal net capacity in FY23 was a result of decommissioning wells on the Wairakei steam field. Increases in
FY24 and FY25 related to Tauhara and Te Huka 3 respectively.
Whirinaki
Wairakei total mass extracted, and extracted volumes as a % of consented
mass take, were significantly down on FY24 as a result of a planned outage
(25 days) at Te Mihi and an electrical outage at Wairakei A&B station.
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 FY28 are indicative.
Upcoming geothermal statutory turnarounds (outages)
2
Plant
Impact
(GWh)
FYFrequency & type
Tauhara
11326Y1 Stat Turnaround
Te Huka 3
3726Y1 Stat Turnaround
Wairakei25264y Stat turnaround
Te Huka 1&2
25274Y Stat Turnaround
Wairakei300274y Stat turnaround + ext works
Poihipi31284y Stat turnaround
Te Mihi Stage 27328Y1 Stat Turnaround
Tauhara
16928Y3 Stat Turnaround
Te Huka 3
3728Y3 Stat Turnaround
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
FY2137789%34%1,126193217
FY2237784%20%673180121
FY2337785%5%16410718
FY2437782%42%1,395184257
FY2537789%21%692330229
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
FY2178484%54%3,698167617
FY2278483%57%3,940121478
FY2378484%57%3,91974290
FY2478490%53%3,628164594
FY2578487%48%3,297163538
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
FY2142589%84%3,114175546
FY2242597%91%3,283140458
FY2341094%89%3,18580254
FY2458694%89%3,388177 601
FY2563590%84%4,543186845
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
FY2120290%13%23423054
FY2220253%10%17921238
FY2320277%8%14820731
FY2420250%12%22317539
FY2520270%22%37821782
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
FY2115894%0%184107.5
FY2215895%0%45972
FY2315882%0%24911.2
FY2415897%0%16871.1
FY2515892%1%1866112
Operational data

48
Hawea storage (GWh)
Gas storage (PJ)
Closing storage
Closing storage (current)
Fuel storage movements
Source: NZX Hydro data
166
260
113
252
188
141
85
263
324
190
322
265
242
232
330
174
-231
-334
-183
-326
-291
-286
-151
-278
1H222H221H232H231H242H241H252H25
Inflows
Opening storage
Releases
259
116
253
191
139
87
264
160
5.8
7.8
4.7
2.4
3.4
2.8
1.6
3.4
2.4
0.5
2.7
1.7
0.9
1.3
3.1
1.9
-3.5
-0.7
-0.7
-1.5
-2.5
-1.3
-2.0
-4.3
-0.4
1H222H221H232H231H242H241H252H25
Gas Injected
Gas Extracted
Opening Storage
7.8
4.7
2.4
3.4
2.8
1.6
3.4
3.3
Operational data
0
Transferred to
long-term
storage (PJ)
04
44444
Long-term storage