Contact Energy FY26 Result: A year of delivery

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
10 August 2026


Contact Energy FY26 Result: A year of delivery


Twelve months ended 30
June 2026 (FY26)*
Twelve months ended 30 June
2025 (FY25)

Reported Against underlying
i

EBITDAF
ii
$1,011m ↑ 31% from $774m
Profit $423m ↑ 62% from $261m
Profit per share 41.5 cps ↑ 27% from 32.7 cps
Operating free cash flow
iii
$648m ↑ 49% from $434m
Operating free cash flow per share 64.0 cps ↑ 18% from 54.4 cps
Average ROIC
iv
5.9% ↑ 100bp from 4.9%
Total assets $10,661m ↑ 56% from $6,813m
Stay-in-business capital expenditure (cash) $145m ↑ 32% from $110m
Growth capital expenditure (cash) $375m ↑ 3% from $363m
* Includes Manawa from 11 July 2025. Prior period does not include Manawa.
Strategic highlights
• Completed Manawa acquisition and integration; adding 2.4TWh renewable output in-year.
v

• Added new flexibility with first 100MW battery online. Started construction on another 200MW.
• Expanded flexible supply agreement to support NZ Steel’s electric arc furnace.
• Progressed construction of Te Mihi Stage 2 geothermal and advanced Tauhara 2 drilling.
• Entered commissioning of Kōwhai Park solar. Confirmed Glorit solar investment.
• Secured consent for Southland Wind Farm with a pathway to supply NZAS potline 4.
• Contracted 50MW HFO to manage dry year risk and support security of supply.
• Entered All-of-Government gas supply agreement, for schools, hospitals and public entities.
• Supported 165,000 retail customers to take advantage of off-peak energy.
vi

• Launched The Good Initiative; more than 60 community groups supported.
Delivering financial performance through Manawa integration and renewable investment
Contact Energy has reported net profit of $423m in FY26 and operating earnings (EBITDAF) of
$1,011m. The period includes the acquisition of Manawa Energy from 11 July 2025, which
contributed to the uplift in earnings.

The improved operating result was driven by a significant lift in renewable output, up 2.9TWh
including PPAs, with total output 98% renewable in FY26. This reflected the addition of the
Manawa hydro assets and its contracted PPAs (wind and geothermal), which together
contributed 2.4TWh, along with a full period of generation at Contact’s new Te Huka 3
geothermal plant. Higher renewable output supported increased contracted sales.
With national hydro inflows in FY26 at 118% of mean, and New Zealand’s hydro storage ending
the period 135% of mean, market conditions contrasted sharply with those of FY25. Average
pricing on electricity sold was lower at $140/MWh, down 11% from $157/MWh in FY25, reflecting
the normalisation of market conditions from a challenging FY25. CFD sales were at lower prices,

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reflecting generation costs. Contact spent less on gas purchases and acquired generation, costs
of which were more expensive in FY25 when fuel was scarce.
The acquired Manawa irrigation business contributed to a lift in other income. In FY25 other
income was affected by losses on the sale of excess gas to Methanex. Operating costs reflected
the combined operations of Contact and Manawa. Cost-reduction synergies of $28m have been
secured on a run-rate basis, 100% of target, with $22m recognised in FY26 within other operating
costs.
“The 2026 financial year has been transformational for Contact, with the completion of the
Manawa acquisition and the welcoming of its people and assets. The strong performance of the
combined entity has set us up well as we move forward to execute the Contact31+ strategy,” said
Chief Executive, Mike Fuge.
Operating free cash flow of $648m was up 49% on FY25, driven by the acquisition, improved
operating performance and a positive movement in working capital. This was partly offset by
higher interest and tax paid and higher maintenance capex reflecting the larger asset base.
In February 2026, Contact raised $575m of new equity. This reduced net debt and will enable
Contact to advance the execution and potential upsizing of renewable energy projects which
would accelerate the Contact31+ strategy.
The Board declared a final dividend of 24 cents per share, taking the annual dividend declared
for FY26 to 40 cents per share. Shareholders will have the option to participate in Contact’s
dividend reinvestment plan at a two percent discount.
Supporting New Zealand’s security of energy supply
In FY26, Contact took pragmatic steps to support New Zealand’s security of energy supply both
for electricity and gas.
In August 2025 we entered into a 10-year agreement with Genesis for 50MW of Huntly Firming
Options (HFOs), mirroring Genesis’ agreements reached in parallel with Meridian and Mercury.
Collectively the agreements help keep Huntly’s Rankine units operational in the event of future
supply constraints in a dry year.
Contact has invested in two grid-scale batteries at Glenbrook near Auckland. The first 100MW
battery came online this March and construction started on a second 200MW battery in that same
month. The second battery is expected online in Q1 2028. This will take Contact’s installed
battery capacity to 300MW, enabling Contact to free up natural gas used in peak periods,
reallocating this to customers.
In September 2025, Contact signed an agreement with the Ministry of Business, Innovation and
Employment to supply gas to around 100 essential public services. The agreement, which runs
for the seven years from 1 October 2025, sees Contact supply around 2PJ of gas a year,
ensuring schools and hospitals have certainty of supply - and price. This was made possible by
the seven-year supply agreement reached in July 2025 with Greymouth Gas.
“Contact’s actions to secure gas for the medium term will support security of supply for essential
institutions like schools and hospitals, as well as Kiwi businesses and homes. This way we can
help them continue to operate and walk alongside them as they transition to a renewable energy
future,” said Mr Fuge.
Supporting customers backed by renewable growth
In line with its strategy to lead New Zealand’s renewable energy future, Contact continued
construction across its committed solar, geothermal and battery projects and has further
advanced development options from its 11TWh p.a. pipeline. Contact continues to work closely

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with existing and potential customers to align proposed future developments with their
requirements.
In August 2025, Contact entered a new 11-year 50MW supply agreement with major industrial
customer NZ Steel to cover periods of higher production from its new electric arc furnace. The
agreement for additional energy mirrors the structure of the 30MW off-peak deal reached in 2023,
giving NZ Steel long-term renewable energy supply for the ongoing operation of its wider
business.
“Long-term, flexible electricity supply solutions like these can work for a wide range of customers
looking for reliable, renewable energy; all while supporting security of supply,” said Mr Fuge.
Contact continues to extend its advantage as New Zealand’s geothermal leader, with
construction well progressed at the Te Mihi Stage 2 geothermal development. The plant is
scheduled to be online in Q3 CY2027 and will deliver baseload renewable generation to partly
replace output from the 1950s-built Wairakei geothermal station. At Tauhara, pre-FID drilling has
been underway to advance steamfield development for the proposed Tauhara 2 geothermal
plant.
Commissioning is underway on the Kōwhai Park solar farm built through Contact’s joint venture
with Lightsource bp. The joint venture’s second project, the Glorit solar farm, reached financial
close in June. The summer-weighted generation from these solar farms is well suited to support
the ~0.5TWh p.a. of dairy electrification load that Contact has under contract.
“Since 2021, Contact has maintained a continuous infrastructure build programme, with $2.4
billion committed to renewable projects in the last five years. Our investment has helped to bring
the market back into supply and demand balance. Long-dated futures prices have reduced by
around 30% since the start of the year, currently at the lower end of our view of long-run
wholesale prices,” said Mr Fuge.
In April, consent was granted for Contact’s proposed Southland Wind farm; expected to deliver
an average annual output of more than 1.2TWh. Contact has signed a letter of intent with Rio
Tinto for a PPA to support the potential restart of 50MW line 4 potline at NZAS, new demand that
would be backed by generation at Southland Wind. Contact has also further advanced its
process to identify a strategic wind partner for its extensive wind pipeline.
Contact has today separately announced that it is working together with CDC Data Centres
(CDC) to explore a potential data centre development at Stratford, Taranaki. For details see the
release “Contact partners with CDC to explore data centre development”.
Leading the energy transition at home
Total retail connections reached more than 690,000 across electricity, gas, broadband and
mobile, up 50,000 on FY25. The continued focus on multi-product customer growth saw the
increase of around 15,000 in the period compared to FY25.
Supporting New Zealanders, Contact continued to see growth in its Time-of-Use products with
more than a third of customers on Good Plans that offer free, or discounted power in return for
shifting usage to off peak periods. Around 165,000 households are taking part, up from 144,000
last year. Since launching in August 2021, customers have received more than 403 million hours
of free power. We have expanded our Hot Water Sorter programme to 30,000 households, up
around 50% on last year, shifting 13GWh of electricity use out of peak periods in FY26.
Last winter, backed by $5m for FY26, Contact launched The Good Initiative, a grassroots
programme to support communities and customers in need. In its first year, Contact has
partnered with 60 community groups, covering the cost of energy, and provided more than
23,000 instances of support to New Zealand households and communities. Contact’s investment
in The Good Initiative will increase to $7.5m in FY27 to further support customers in need. Our

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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 advancing the execution of its
Contact31+ strategy, launched in November 2025.
“I have huge aspirations for New Zealand and the part the renewable energy economy must play
in creating jobs, building regional communities, powering manufacturing, attracting new industry,
and growing the country’s export earnings. We have a clear strategy, strong balance sheet and
the proven execution capability to see us lead New Zealand’s renewable energy future,” said Mr
Fuge.

1/ CONTACT DETAILS
Investor enquiries Media enquiries
Shelley Hollingsworth Louise Wright
Head of Strategy and Investor Relations Head of Communications and Reputation
+64 27 227 2429 +64 21 840 313
investor.centre@contactenergy.co.nz media@contactenergy.co.nz

2/ CONFERENCE CALL
A conference call will be held at 11am NZDT on 10 August 2026 regarding Contact’s FY26
results announcement. 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 enter the webcast: LIVE EVENT LINK
Or access this link via our website: https://contact.co.nz/aboutus/investor-centre

i In FY25, the release of the Ahuroa Gas Storage (AGS) onerous contract provision increased reported EBITDAF by $98M and profit by $71M.
These impacts have been removed from underlying performance. All variances reflect year-on-year changes in underlying performance.
ii
Refer to slide 46 of the FY26 results presentation for a definition and reconciliation between statutory profit and the non-GAAP performance
measure earnings before net interest expense, tax, depreciation, amortisation, asset impairment and write-offs, and changes in fair value of
financial instruments (EBITDAF).
iii
Refer to Note A3 of the 2026 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 Refer to slide 19 of the FY26 results presentation for a definition of average return on invested capital (ROIC).
v
Includes 0.8TWh renewable output acquired through long-term Power Purchase Agreements (PPAs).
vi As at 30 June 2026.

---

1
1
2026 full year results
presentation
10 August 2026
Twelve months ended 30 June 2026

2
Disclaimer and important information
This presentation contains summary information and statements about Contact and its
businesses and activities as at the date of this presentation. The information is not held
out as being complete or exhaustive, nor does it contain all the information which a
prospective investor may require in evaluating a possible investment in Contact.
While all reasonable care has been taken in compiling this presentation, neither Contact
nor any of its directors, employees, shareholders nor any other person gives any
representation as to the accuracy or completeness of this information or accepts any
liability for any errors or omissions.
Contact recommends that you read this presentation in conjunction with both its market
announcements and the materials attached to those announcements, and in particular
the market announcements and materials itreleased on the date of this presentation.
These are available on the NZX website (at www.nzx.com), ASX website (at
www.asx.com.au) and on Contact's website (www.contact.co.nz).
This presentation may contain certain forward-looking statements with respect to a
variety of matters. All such forward-looking statements involve known and unknown risks,
significant uncertainties, assumptions, contingencies, and other factors, many of which
are outside the control of Contact, which may cause the actual results or performance of
Contact to be materially different from any future results or performance expressed or
implied by such forward-looking statements. Such forward-looking statements speak only
as of the date of this presentation. Except as required by law or regulation (including the
NZX Listing Rules and the ASX Listing Rules), Contact undertakes no obligation to
update these forward-looking statements for events or circumstances that occur
subsequent to the date of this presentation or to update or keep current any of the
information contained herein. Any estimates or projections as to events that may occur in
the future (including projections of revenue, expense, net income and performance) are
based upon the best judgement of Contact from the information available as of the date
of this presentation.
EBITDAF, free cash flow, 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
Agenda
FY26 Highlights
Mike Fuge
Chief Executive Officer
Financial results &
outlook
Strategy update
Matt Forbes
Chief Financial Officer
Supporting materials
Mike Fuge
Chief Executive Officer
Slides 4 to 9
Slides 10 to 22
Slides 23 to 29
Slides 31 to 51

4
FY26 highlights
Total shareholder return FY26
Continued representation within
DJ BIC Asia Pacific and MSCI indices
Delivering for
shareholders
Manawa acquisition completed
100%of the$28M identified
cost synergies secured (run-rate basis)
Manawa hydro and PPAs increased
renewable output by 2.4TWh in FY26
Generation at new Te Huka 3
geothermal plant 0.4TWhin FY26
Contracted 50MW Huntly Firming
Option for 10 years to manage dry
year risk, supporting security of supply
Delivering portfolio
change
Delivering renewable
energy growth
Delivering financial
performance
Delivering for
customers
Delivering for
the market
+9%
+37%
Renewable output YoY
renewable in FY26
3
98%
Financial close reached on Glorit solar
150MWac / 287GWh p.a.
Kōwhai Park solarin commissioning
150MWac / 275GWh p.a.
Glenbrook-Ohurua
100MW battery online and 200MW
battery under construction
+31%
+62%
NPAT $423M
up $162MYoY
EBITDAF
1
$1,011M
up $237M YoY
40cps
Total dividend
Average ROIC
2
5.9% up 100bpsYoY
+100bps
Commenced electricity supply to
NZ Steel’s new EAF
4
AoG
5
contract providing 2PJ
ofgas to core community assets
165khouseholds choosing
discounted or free off-peak energy
6
Contact Good Initiative $5M
supporting customers and communities
1. Refer to slide 46for 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). FY25 EBITDAF is an underlying figure that excludes release of the AGS onerous contract provision that increased reported EBITDAF by $98M and profit by $71M. |2ROIC average is calculated as NOPAT (4-year average) /
Average IC (4-year average). Refer toslide 19 for the operating free cash flow reconciliation and for the basis of calculation of return on invested capital. | 3. Renewable generation includes wind and geothermal PPA purchases but
excludes short-term acquired generation purchases e.g. fuel replacement via ASX which will reflect the renewable mix of the market | 4. Electric Arc Furnace (EAF). | 5. All of Government (AOG). | 6. As at 30 June 2026.

5
New Zealand electricity market was 93% renewable in FY26
Inflows & hydro:
Hydro inflows 118% of post market mean.
1
Total market renewable percentage was
93%
2
, the highest rate achieved since the
market was introduced.
Network and transmission
pressures continue:
Lines cost increases
from 1 April 2025.
8
Demand returns:
Demand was robust, up ~3% on FY25,
~1% normalised for NZAS
6
demand
response.
7
Gas production continues to decline:
2P Gas production forecast for 2027
is down 24% compared to the
same forecast last year.
9
High inflows, energy storage and record renewable generation have led to subdued pricing
1. Source: NZX Hydro. |2. Source: EMI. | 3. Source: Electricity Authority. Generation output by plant. | 4. AhuroaGas Storage Facility (AGS). |5. Source: ASX.Change in ASX Settlement prices at Otahuhu for Q3 2026 from 31
December 2025 to 30 June 2026. | 6. New Zealand Aluminium Smelters Ltd. On 1 July 2024, responding to dry market conditions, Meridian called on its demand response contract with NZAS resulting in operations being
turned down and demand for electricity being reduced temporarily in 1H25. | 7. Source: EMI and Contact. | 8. Source: Commerce Commission. 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). |9. Source: MBIE electricity & gas data.
ASX futures soften:
Winter 2026 pricing fell by more than
60% over 2H FY26, reflecting high energy
storage.
5
Longer-term futures pricing fell 27% over
2H FY26,
2
with the market moving into
supply / demand balance on the back of
renewable generation investment.
Energy storage:
FY26 ended with hydro lakes at 135% of
mean
3
, gas storage (AGS
4
) close to full, and
the Genesis coal stockpile at 1,189kt (up
70% on prior year), all contributing to low
fuelling risk for winter 2026.
Market update

6
▪NZAS now operating on long-
term supply contracts coupled
with demand response.
▪1TWhof committed dairy
electrification projects to be
supported by summer-
weighted generation.
▪NZ Steel’s Electric Arc Furnace
backed by shaped supply
contract.
▪Market and regulatory settings
have evolved alongside the
energy transition.
oNon-discrimination
obligations and super-peak
market making have been
implemented.
oEnhanced EA enforcement
and regulatory powers have
been introduced.
▪NZAS demand response
mechanisms in place for dry
year support.
▪Huntly Firming Options
signed to support dry year
capacity.
▪Strategic coal reserve and
stored gas and hydro.
▪Fast Track consenting
regime now operating.
▪New renewable generation
added 4TWh over the last
five years (BCG).
1
▪Electricity market reached
93% renewable in FY26.
▪Industry-wide focus on energy
wellbeingconsumer care and
reducing barriers to access.
▪Disconnections viewed as last
resort.
▪No disconnection or
reconnection fees (Contact).
▪In FY26 Contact Good Initiative
provided ~$5M of customer
and community support.
The market has adapted for the energy transition
Investing at
pace in
renewable
energy
Managing fuel
security and dry
year risk
Enhancing
market
settings
Supporting
energy
wellbeing
Sector investment, customer innovation and market settings have all advanced as New Zealand has progressed through the energy
transition
▪RMA Reform: Planning and
Environment Bills expected to
pass by end of year.
▪~3TWh of generation either
committed or under
construction and expected to
come online by 2027.
2
▪Consultation to conclude in 2026 on MBIE’s proposed Winter
Reliability Obligation framework.
▪Potential to extend HFO for further dry year support.
▪Potential for right-sized LNG import terminal to enhance fuel
diversity.
▪Potential for diesel storage as an additional strategic reserve.
▪Contact advocating for a
market-wide obligation to
connectto further lift energy
wellbeing outcomes.
▪$7.5M committed through
Contact Good Initiative in
FY27 to support customers
and communities.
Delivered
Looking ahead
Innovating for
industrial and
commercial
customers
▪Potential reopening of NZAS
Line 4 potline at Tiwai Point.
▪Continued dairy
electrification, aligned to
summer load.
▪Estimated New Zealand data
centre capacity of up to
~725MW by 2035 (Invest NZ).
3
1. Boston Consulting Group. Energy to Grow: Securing New Zealand’s Future (2025). ​| 2. Company announcements and Contact’s analysis. ​| 3. Invest New Zealand, Data and AI infrastructure Report (2026). Data
based on base case scenario.
Market update

7
Renewable investment programme continues
Glenbrook-Ohurua
Battery 2
200MW / 400MWh
Target online Q1 CY28
Target IRR >10% at FID
3
Te Mihi Stage 2
Geothermal
101MW / ~840GWh p.a.
(~200GWh net uplift)
4
Target online Q3 CY27
Target IRR ~10% at FID
3
Glorit
Solar
150MWac / 287GWh p.a.
Target online Q4 CY28
Target IRR >12% at FID
2
Te Mihi Stage 2
•Construction underway.
Earthworks began March 2026.
•Battery packs under
construction with lithium price
locked in second half 2025.
•Steamfieldseparator, heat
exchangers and turbines for the
first unit installed. Cooling
tower nearcomplete.
•Delays being incurred in
equipment delivery, in part due
to global shipping constraints.
•Target online remains Q3 CY27.
•Financial close reached in
June 2026.
•Early works underway.
•Notice to proceed issued to
EPC contractor.
1. Total construction cost over the life of the projects including joint venture and project financing (solar). | 2.Target Contact IRR includes joint venture returns and margin on acquired generation. Return on
acquired generation will ultimately depend on sales channel and market conditions. | 3. Representing target ungeared project IRRs. | 4. Indicative average uplift from new generation accounting for the planned
partial closure of Wairakei geothermal station.
Glenbrook-Ohurua
Battery 2
Glorit
Auckland
Wellington
Strategy delivery
Current projects under construction represent ~$1.3b of investment
1
, ~0.5TWh of net new generation
Under construction:
Kōwhai Park
In commissioning
Glenbrook-OhuruaBattery 1
Online Mar 2026
Te Huka 3
Online Dec 2024
Tauhara
Online May 2024
Recent projects –Continuous build programme since 2021:
+275GWh p.a.
+100MW / 200MWh+430GWh p.a.+1,450GWh p.a.

8
Benefits from Manawa integration realised
Strategy delivery
An $84M uplift has been secured in FY27, excluding benefits from generation normalisation, 35% higher than the long-run benefit
indicated at deal announcement
22
28
FY26FY27
Opex synergies delivered,$M (in-year)
Integration benefits secured, FY27
1
100%
of identified cost
synergies have been
secured at $28M
(FY26 exit run-rate basis)
$23M to $28M
targeted at deal
announcement
EBITDAF
uplift $M
Change
$/MWhGWh
2652500Mercury volume resold to C&I and CFD channels
2
4450869Mercury volume shifted to ASX-linked pricing
3
(14)(22)640Mercury wind PPA repricing
56Net repricing benefit
28Cost synergies achieved (FY26 exit run-rate)
84Total uplift
Integration benefits of
$84M
secured for FY27
(excluding generation normalisation)
1
+35%
on long-run expected
benefits indicated at deal
announcement
Legacy Manawa development options Huriwaka
(wind), Kaihiku(wind)
4
and Argyle (solar) are being
actively advanced.
Together they represent potential to contribute
2.1TWh p.a. of output.
5
Development pipeline advanced
1. Benefits have been illustrated excluding generation normalisation as this can be expected to fluctuate year on year with hydrology and wind conditions. | 2. Indicative price change reflects a mix of FY27
channel pricing of $168/MWh for C&I (net price) and $155/MWh for CFD, which are 95% and 98% sold respectively. Compared to fixedprice in FY26. Includes portfolio benefit of $16M givenContact’s ability
to sell 300GWh of Manawa generation that would previously be held as a risk buffer.| 3. Repriced with reference to ASX. As at publication, ~97% of FY27 repricing is confirmed. Compared to fixed price in
FY26. | 4. Kaihikuis a 50:50 JV with Pioneer Energy. | 5. All development options remain subject to FID. Pending appropriate market conditions and projects meeting returns thresholds.

9
Contact has delivered on the FY26 plan
​FY26 operational plan
▪Multi-product customers >156k (up from 149k).
Decarbonise
our portfolio
Create
outstanding
customer
experiences
​Strategic theme
Impressive delivery of the strategic targets outlined at the start of the year
Manawa
integration
In-year benefits target:
▪Targeting net price up by ~2%.
Exit run-rate benefits target:
1. Cumulative measure, shown on a total contracted basis. | 2. Total retail operating costs (direct and indirect) / average connections. Includes customer acquisition costs. This is $113 per connection based on
closing connections.| 3. This is a through-the-cycle measure. Actual result will be impacted by hydrology, fuel and other market conditions. | 4. Based on the sale of 300GWh risk management buffer at a blend of
FY27 CFD and C&I pricing. Refer to slide 8 for detail.
▪Cost to serve <$116/connection.
2
​FY26 achieved
▪Opex reduction $10M to $20M.
▪Portfolio benefits $5M.
3
▪Opex reduction $22M to $25M.
▪Portfolio benefits $10M to $20M.
3
Multi-product customers 165k.
Net price target exceeded.
Cost to serve $117per connection.
2
Opexreductionof $22Machieved in-year.
Portfolio benefits >$5M achieved in-year.
Portfolio benefits of $16M secured for FY27.
4
Exit run-rate achieved.
Opexreduction exit run-rate of $28Machieved.
▪Close TCC gas generation plant late CY25.
▪Sustained New Zealand leadership position in the Asia Pacific DJSI.
▪Scope 1 & 2 emissions <650ktCO
2
e.
TCC closed, at end-of-life, after 30 years in service.
FY26 Scope 1 & 2 CO2e of 319kt (gross).
Contact maintained in the Dow Jones Best-in-Class Asia
PacificIndex(formerlyAsia Pacific DJSI).
▪Achieve FID for CO
2.
Grow
Demand
▪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).
The CO
2
project is under development with active technology
trials underway.
New demand facilitated since FY21 is 258MW of which 157MW is
currently operational. Additional 101MW expected online in FY27.
New in-year demand contracted in FY26 of ~28MW of which
26MW issummer-weighted.
▪Glenbrook-Ohurua Battery 1 online Q1 CY26.
Grow
renewable
development
Subject to market conditions and obtaining consents, achieve FID on:
▪Consents lodged on at least 2 renewable development projects.
▪Kōwhai Park solar online Q2 CY26.
▪Te Mihi Stage 2 geothermal on track for online Q3 CY27.
▪Solar (e.g. Glorit, Argyle); and/or
▪Glenbrook-Ohurua Battery 2 (200MW).
Glenbrook-Ohurua Battery 1 online in March 2026.
Te Mihi Stage 2 on track to be online for Q3 CY27.
Kōwhai Park in commissioning, expected online Q3CY26.
Lodged for Glenbrook-OhuruaBattery 2 and Stratford hybrid-solar.
FID achieved (Glorit). Reached financial close in June 2026.
FID achieved. Construction underway.
Strategy delivery

10
Financial results
and outlook

11
Twelve months ended
30 June 2025 (FY25)
1
Twelve months ended 30
June 2026 (FY26)
1
Against underlying
2
Reported
3% from $3,306M↓$3,206MRevenue
3
31% from $774M↑$1,011MEBITDAF
4
900bps from 23%↑32%EBITDAF margin
62% from $261M↑$423MProfit
27% from 32.7c↑41.5cProfit per share
49% from $434M↑$648M
Operating free cash
flow
5
18% from 54.4c↑64.0c
Operating free cash
flow per share
5
100bps from 4.9%↑5.9%Average ROIC
18% from $355M↑$419MDividend declared
3% from 39.0c↑40.0c
Dividend declared per
share
32% from $110M↑$145M
Stay-in-business(SIB)
capital expenditure
(cash)
3% from $363M↑$375M
Growth capital
expenditure (cash)
6
Summary of key financial performance measures
Strong result with $1,011M EBITDAF reflecting investments in
renewable generation
1. Includes Manawa from 11 July 2025. Prior period does not include Manawa. | 2. In FY25, the release of the AGS onerous contract provision increased reported EBITDAF by $98M and profit by $71M. These impacts
have been removed from underlying performance. All variances and commentary reflect year-on-year changes in underlying performance. | 3. Revenue figures align with the treatment of realised movements in
financial instruments within the segment note of the financial statements.| 4. FY26 EBITDAF was$1,037M excluding Manawa transaction and integration costs of $26M. Refer to slide 46for a definition and
reconciliation of profit to EBITDAF. | 5. Refer to slide 19 for a reconciliation of operating free cash flow. | 6. Includes capitalised interest.
Delivering on the benefits of
the Manawa acquisition with
100% of cost synergies
delivered: $22M in-year
($28M run-rate basis)
TCC closureand reduction
in gas generation (down
79% on FY25)
Increasing sales to major users
in the long-term inflation-
protected, strategic fixed price
sales channel
Manawa acquisition added
2.4TWh of additional volume
in-year from hydro generation
and PPA contracts
Glenbrook-OhuruaBattery 1
online, shifting 11GWh of
volume in the first 3 months
of operating
Key themes from the results
Record performance
reflecting greater scale
from renewable
development and the
Manawa acquisition

12
Profit, $M
EBITDAF up $237M (31%) on FY25 (underlying), reflecting the Manawa acquisition and increase in renewable generation
Profit of $423M for FY26
EBITDAF, $M
Prior period gas
and acquired
generation prices
were elevatedby
short-term
Methanex gas,
NZAS demand
response and fuel
scarcity
conditions.
Combination of
higher channel
pricing and a mix
shift between
strategic and
retail channels.
Renewables up
with the addition
of Manawa
generation,
normalisation of
hydro output, and
a full year of Te
Huka 3.
This now includes
Manawa irrigation
income.
Prior period
included losses on
sale of excess
Methanex gas.
4
3
1
FY26 results
FY25
EBITDAF
1
1. Renewables
2. Net
volume
2
Higher contracted
sales volumes
underpinned by
higher generation
and Manawa
contracted sales
acquired as part of
the transaction.
6
3. Long Term
channel
pricing
5.Gas, carbon
and acquired
generation
price
6.Other
income
122
88
40
51
103
98
774
-21
-32
-8
-106
872
225
-114
1,011
4.Market
channel
pricing
Hydro conditions
led to a
normalisation of
CFD prices. These
were elevated in
FY25 as risk
management
contracts reflected
challenging
market conditions.
5
7
7.Fixed
operating
costs
Manawa fixed costs,
inflation impacts, non-
recurrence of AGS
provision unwind benefit
and transaction and
integration costs
($8M higher than
prior period).
Partly offset by in-year
cost synergies and
productivity benefits.
FY25 profit
1
Net
interest
costs
EBITDAFDepreciation
& Amortisation
TaxChange in
FV of
financial
instruments
FY26 profitAsset
impairment
/ write-offs
FY26EBITDAF
AGS onerous contract release (pre-tax)
Acquired Manawa hydro (measured at GWAP)
Manawa transaction & integration costs
261
423
237
39
71
-21
-40
17
-8
-62
331
56
AGS onerous contract release (after-tax)
Realised change in FV of financial instruments
Unrealised change in FV of financial instruments
1. In FY25, the release of the AGS onerous contract provision increased reported EBITDAF by $98M and profit by $71M. These impacts have been removed from underlying performance. All variances and commentary reflect
year-on-year changes in underlying performance.
32.7
41.5
Profit per
share, cps

13
Wholesale EBITDAF, $M
1
Retail EBITDAF,$M
Corporate / unallocated costs, $M
Operating performance by segment
EBITDAF up by $237M
Refer to slides 14 -16
Refer to slide 17
-49
-41
FY25
0
Electricity
Volumes
125
130
Electricity
Prices
17
Other
products
2
4
OpexFY26
+7
Electricity gross
margin
(-$6M)
Electricity
and
network
cost
inflation
Price
recovery
2.Other products includes retail gas and telco gross margins.
FY26 results: Segmental performance
1. Simply and Western included within Wholesale EBITDAF.
EBITDAF is shown excluding a $98M provision release in FY25
(underlying EBITDAF).
3. Increase net of in-year synergies. | 4.Stats NZ CPI increase
over the 12 months to June 2026 plus wage inflation.
55
18
FY25
6
Transaction
&
Integration
Cost
Increase
9
Acquired
Manawa
corporate
costs
5
Inflation &
Non
Recurring
69
24
FY26
-73
-93
-20
4
Manawa transaction & integration
895
1,145
281
FY25
15
Generation
costs
(including
acquired
generation)
Total
contracted
revenue
15
Trading,
merchant
revenue
and losses
FY26
+250
3

14
Electricity generated or acquired, GWh
Generation volume rises significantly, reflecting greater scale and portfolio diversity
FY25FY26
Electricity generated or acquired costs, $M
Generation costs
FY26 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
•
Contribution from Manawa hydro assets and a normalisationof
hydro output led to a 53% increase (1,735 GWh) in hydro
generation. Despite high inflows, generation was ~718GWh below
Contact’s mean expectation for FY26 (5,750GWh) owing to a
period of spill in summer 2025.
•
Geothermal volumes were up 371GWh on FY25 (8%) supported
bya full period of TeHuka 3. This was partially offset by statutory
outages at Tauhara, TeHuka 3 and Wairakei.
•
Thermal generation supported Winter 2025, however, strong
hydro inflows and new renewables brought online in the last 18
months reduced the need for thermal with generation falling
859GWh, 79% year on year.
•
PPA purchases of827GWh in FY26 reflected wind and
geothermal PPAs acquired with Manawa.
•
Market acquired generation was purchased to cover geothermal
statutory outages and when spot prices were advantageous.
Totalvolume was up 223GWh on FY25. Costs were $84.4/MWh
lower than FY25 despite HFO premiums now being included.
Costs
•
Renewable generation costs were up $69M (46%) on FY25,
including $66M from hydro ($53M driven by operating new
stations).
•
Thermal generation costs were down $139M (-60%) on a lower
cost of gas per unit (FY25: $15.4/GJ, FY26: $13.9/GJ).
4,543
4,914
3,297
5,032
1,088
462
685
827
FY25
229
FY26
PPA purchases
Market acquired
Thermal
Hydro
Geothermal
9,390
11,687
134
197
149
37
218
41
233
143
94
27
122
61
203
26
31
122
80
123
8
Generation
type
14
Cost
type
11
Generation
type
Cost
type
511511
526
526
+15
88%
Renewable % of
own generation
98%
$54.40/MWh
$44.96/MWh
1. In FY25, gas storage costs included a $14.6 million provision unwind released
throughout the year.
Development
Market acquired
PPAs

15
601
657
169
307
471
312
146
361
4
5
-9
FY25
37
5
-12
FY26
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
1,386
1,666
+281
3,675GWh
$178.7/MWh
Contracted
revenue, $M
Diversified mix of long-term and ASX-linked sales channels
2,008GWh
$155.4/MWh
-14GWh
+$15.8/MWh
-289GWh
-$49.5/MWh
Contracted wholesale revenue increased in aggregate as Contact made
additional sales backed by the addition of the Manawa assets and PPAs.
•
Sales to the retail segment were down 14GWh as lower average customer
usage offset growth in customer connections during FY26. Pricing on sales
to retail increased by $15.8/MWh to $178.7/MWh, reflecting higher wholesale
electricity prices over recent years.
•
C&I channel sales were up 694GWh driven by growth in customer contract
volumes, including the addition of contracts acquired through the Manawa
transaction. Net Price increased $20.6/MWh reflecting contract repricing and
the inclusion of higher-priced contracted volumes acquired through
Manawa.
•
CFD sales volumes were down 289GWh as a greater proportion of
contracted sales were directed into strategic long-term channels and C&I
contracts. Hydro conditions led to a normalisationof CFD pricing, down
$49.5/MWh to $155.4/MWh. Prices were elevated in FY25 as risk
management contracts reflected challenging market conditions.
•
Strategic fixed price volumes were up 2,180GWh driven by the acquisition of
the long-term Mercury CFD from Manawa, a full year of Tauhara-linked
CFDs, increased sales to NZAS and the commencement of the NZ Steel
contract. Prices were up by $7.8/MWh as new long-term agreements better
reflect Contact's long-run view of electricity pricing.
•
Other income was $33M higherdue to the inclusion of irrigation net income
from Manawa (+$11M), non recurrence of gas sold at a loss in FY25 (+$14M)
and Peaker GT22 insurance proceeds ($12M).
Wholesale contracted revenue
1,864GWh
$164.7/MWh
+694GWh
+$20.6/MWh
FY26 results: Wholesale business
3,907GWh
$92.5/MWh
+2,180GWh
+$7.8/MWh
Year-on-year
changes to
volume and
price
FY26 volumes
and price

16
Trading EBITDAF, $MLong / short position, GWh
9.0%
($7.4/MWh)
1.5%
($1.2/MWh)
In FY26 high hydro inflows coupled with strong
wind conditions in 1H26 and the addition of new
renewable generation brought online in the last 12
months led to subdued spot prices. FY26
conditions were shaped by:
•
Elevated but highly concentrated hydro inflows
led to spill, reducing hydro output.
•
High wind conditions in 1H26 compounding the
increase in supply and adding to spill conditions.
•
Subdued wholesale spot prices throughout the
year.
•
A shift away from merchant exposure, to long-
term contracts.
Contact’s LWAP/GWAP spread fell to ~1% on the
back of revised portfolio dynamics following the
Manawa integration and geothermal build, very
low spot prices, and improved FTR
1
outcomes. This
resulted in a very low absolute LWAP / GWAP
spread, significantly reducing Contact's LWAP /
GWAP losses.
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
$80.4MWh
Spot purchases and
sell CFD settlement
Spot sales and buy
CFD settlement
Merchant generation
100
19
-80
-14
FY25FY26
20
5
507
8,883
-8,883
FY25
11,464
-11,464
FY26
507
234
234
FY26 results: Wholesale business
LWAP/GWAP
losses
$197.9MWh
Trading EBITDAF reflected reduced merchant exposure and subdued wholesale spot prices
1. Financial Transmission Rights(FTRs).

17
1
Retail business performance
EBITDAF, $M
Retail EBITDAF up $7M despite higher energy and lines costs, supported by Gas and Telco margin growth and 50k connection growth
VarianceFY26FY25
Revenue & Tariff
,
$M
Tariff$MTariff$M$M
+$38/MWh128$350/MWh1,2071,079
Electricity revenue
-$2/GJ95$47/GJ198103
Gas revenue
-$1/connection16$71/cn117101
Telco revenue
-347
Other income
2371,5271,290
Total revenue
$134$129
Cost to serve/customer
1
666k633k
Average connections
$117$116
Opex per connection
1. Reflects total operating costs (direct and indirect) less customer acquisition costs / closing customers. | 2. Retail connections and customers only, excludes Simply Energy.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. | 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). Costs are increasing annually.
13
17
18
33
-11
-16
-74
-78
4
FY25
3
FY26
Other
Gas GM
Electricity GM
Telco GM
Other operating
expenses
-49
-41
FY26 results: Retail business
FY26
Gas
642
692
FY25
445
148
465
437
415
124
79
Customers
Telco
Electricity
73
Closing customers & connections
2
, ‘000s
$181/MWh$164/MWh
Energy cost
3
$153/MWh$132/MWh
Networks,
meters and
levies
3
Retail EBITDAF increased by $7M on FY25 largely due tostrong
growth in Gas and Telco margins, partially offset by high wholesale
prices and rising distribution costs:
•
+$130M increase in electricity input costs, which were not fully
passed through to customers.
•
The average Retail electricity tariff increased by +12% reflecting
widespread retail price rises to partially offset higher wholesale
costs and full recovery of lines cost increases.
•
Around 90% of customers received a price increase in the last 12
months.
Cost pressures on the lines component of the tariff are expected to
remain as the increased costs of transmission and distribution
infrastructure continue to be incurred.
4
Moderating wholesale prices are expected to lower the electricity
component over time.
Connections grew strongly throughoutFY26, particularly through
Telcoand Time of Use (ToU) electricity Good plans, with a focus on
multi-product customers.
•
Total connections +50k on FY25with Telco up 24k and Energy
up 26k.
•
Multi-product customers up 10% on FY25, driven by strong
Telco product attachment alongside ToUGood plans growth.
Opex–increased by $1/connection, largely driven by wage
inflation,partially offset by increased connections, and productivity
improvements through continued growth in digitised interactions.

18
Other operating cost movement FY26, $M
FY26 movement commentary
Manawa acquired opex
•
$93M Manawa related opexfrom FY25 Manawa financial statements
($117M) excluding one-off bad debt for Prime Energy (-$7M),
transaction costs (-$7M) and transmission costs which Contact
includes in gross margin (-$10M).
Base movement and headwinds
•
$9M general inflation of 3.1% impacting operating costs. These have
been seen across all cost categories including labour cost.
•
$2M increase in bad debts over Retail mass market and C&I segment
with Kiwi Crunch liquidation.
Synergies & productivity delivered
•
$22M from Manawa related synergy delivered within FY26.
•
$2M related to continued efficiency from Retail cost to serve.
Growth
•
$2M incremental costs with TeHuka 3 online vs prior year.
•
$2M incremental investment related to retail connection growth.
Manawa transaction and integration related costs
•
$8M additional transaction and integration related costs incurred
with transaction related costs up $3M and integration costs up $5M.
Operating costs increase on inflation and growth
FY26 results: Operating costs
93
24
26
276
FY25Manawa
acquired opex
9
2
General
inflation and
headwinds
Synergies and
productivity
4
GrowthFY26
underlying
Manawa
transaction
and
integration
costs
FY26 reported
11
361
387
FY26 Manawa transaction and integration costs
FY25 Manawa transaction and integration costs
General inflation (3.1%)
Headwind & non-recurring costs
11
16
FY26 BAUInflation
4
GrowthSynergies &
productivity
FY27 BAU
361
360
Expected other operating cost movement FY27
1
, BAU $M
18
1. BAU opexwill exclude SaaS implementation and Manawa integration costs.

19
•
Higher EBITDAF on FY25 (underlying), as detailed on slide 12.
•
Working capital change was a positive $20M impact to OpFCF(vs. negative $35M in FY25), mainly due to a
reduction in carbon unit inventory reflecting changes in thermal generation.
•
Tax paidwas $13M higher,reflecting the addition of provisional tax payments for Manawa and KCE groups,
offset by a lower FY25 final tax payment that is paid during FY26.
•
Interest paid, net of capitalisedinterest, rose by $45M. Linked to increased borrowing in support of the
Manawa acquisition.
•
FY26 stay-in-business (SIB) capital expenditure includes previous accelerated programme ($14M),
geothermal and hydro enhancement projects and integration ($12M), Wairakei extension ($21M) and risk-
rated and improvement projects ($98M).
Comparison
against FY25
12 months
ended
30 June
2026
12 months
ended
30 June 2025
$237M
↑
$1,011M
$774MEBITDAF
$55M
↓
$20M
($35M)Workingcapital changes
($13M)
↑
($119M)
($106M)Taxpaid
($45M)
↑
($122M)
($77M)Interest paid, net of interest capitalised
($35M)
↑
($145M)
($110M)SIBcapital expenditure
$15M
↓
$3M
($12M)Non-cash items includedin EBITDAF
$213M
↑
$648M
$434MOperating free cash flow
9.6 c↑64.0 c54.4 cOperating free cash flow per share
up 900bps↑64%55%Cash conversion (OpFCF /EBITDAF)
Return on invested capital (ROIC)
Cash conversion higher driven by strong EBITDAF growth and reduced value of fuel inventory
Cash flow and capital expenditure
Sources and uses of cash, $M
FY26 results: Cash flow
20017496251
NOPAT, $M
1. NOPAT is calculated as annual EBIT less tax (tax includes annual tax expense and movements in deferred tax over the year as aproxy 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
movement in the AGS provision for FY23, FY24 and FY25. | 2. ROIC average is calculated as NOPAT (4-year average) / Average IC (4-year average). | 3.ROIC (FY) is calculated as Annual NOPAT (FY) / Average IC (FY).
648
387
575
375
121
358
253
18
4
47
Sources
3
Uses
1,3951,395
Cash Accumulated
Net debt drawdown
OpFCF
Dividend re-invested
(DRP)
Sale of asset
Strategic investments / acquisitions
Growth investment
Dividends paid
Realised losses on market derivatives
Financing costs
0
1
2
3
4
5
6
7
8
9
3.7%
3.7%
3.3%
3.7%
4.9%
5.9%
ROIC (average)
2
ROIC (FY)
3
475
Net operating profit after taxes (NOPAT) / Invested capital (IC)
1
Average IC, $M
4,482
4,518
4,874
5,349
5,670
7,412
FY21FY22FY23FY24FY25FY26
Equity raise
557

20
Approach and FY26 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 FY26
year-end, the point estimate of net debt to
EBITDAF was 2.1x.
•During FY26, Contact issued an inaugural
€500m European Medium Term Note (EMTN).
This debt was certified against the Green
Bond Principles under Contact’s Sustainable
Finance framework and supported the
funding of the Manawa acquisition.
•Contact repaid the $14M of remaining NEXI
export credit facility and $88M US Private
Placement debt (USPP) early in April and May
2026 respectively and closed out the related
cross currency swaps.
Looking ahead
•The first reset date of the Capital Bond issued
in 2021 is approaching in November 2026.
Contact intends to redeem the bonds at this
reset date and issue a replacement in line with
market expectations.
Post the $575M February equity raise and debt consolidation, Contact is well positioned to advance investments aligned with Contact31+
Closing net debt, $M
Face value of borrowings less cash
Interest rate, %
Weighted average gross interest
1
on average borrowings
Net debt to EBITDAF, X
Includes S&P adjustments
2
Borrowing maturities, $M
Average tenor of 7.2 years as at 30 June 2026
Streamlined balance sheet
1. Gross interest includes all interest on borrowings, bank commitment fees and deferred financing costs. Unwind of leases, provisions and capitalised interest not included. | 2.Illustrated here on a point basis based on
expected S&P adjustments. See breakdown of S&P approach on slide 47.
774
1,025
1,831
2,314
21
-514
-766
-150
FY21
25
-168
FY22
49
1,474
-140
FY23
47
-229
FY24
50
FY25
63
2,905
FY26
645
882
1,383
1,649
1,850
2,202
Lease obligationsBorrowingsCash on hand
250
350
434
435
1,011
225
250
150
350
FY27FY28
300
FY29FY30FY31FY32FY33FY52FY55
400
650
Undrawn bank facilities
Domestic bonds
Capital bonds
AMTN
EMTN
1.4
1.8
2.6
2.7
2.3
2.1
FY21FY22FY23FY24FY25FY26
974
892
1,310
1,727
1,973
5.2%
FY21
5.4%
FY22
5.8%
FY23
6.1%
FY24
5.8%
FY25
5.2%
3,057
FY26
Average gross interestAverage gross debt
FY26 results: Key balance sheet metrics

21
Dividend for FY26 of 40 cents per share
•The final dividend of 24 cents per share is imputed up to 79% or 19 cents per share for qualifying shareholders.
•This takes the total FY26 dividend declared to 40cents per share, representing a pay-out of 65% of FY26
operating free cash flow and 114% of the average operating free cash flow over the preceding 4 financial years
(FY22-FY25).
•The record date is 18 August 2026; payment date is 23 September 2026.
•The NZD / AUD exchange rate used for the payment of Australian dollar dividends will be set on
25 August 2026.
Dividend per share for FY26 up 3% to 40cps
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 FY26 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 19August 2026 to confirm participation in the
plan.
•The trading period for setting the price for the DRP is 17 August 2026 to 21 August 2026. The DRP strike price
will be announced: 25 August 2026.
Ordinary dividends, $M
Declared
Final dividend
Interim dividend
% pay-out of annual operating free cash flow
35
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 FY26.
If the shares issued in FY26 as consideration for Manawa, the February 2026 equity raise, and
the acquisition of KCE are excluded, the dividend declared would represent a pay-out of 50%
of FY26 operating free cash flow and 89% of the preceding 4-year average.
326
261
FY22
333
266
82%
FY23
318
256
92%
FY24
352
282
101%
FY25
368
294
114%
FY26
330
282
➢Annual operating
free cash flow
100%
80%
Dividend level
as a % of preceeding
4yr operating fcf
164
165
181
227
260
109
109
110
128
159
FY22FY23FY24FY25FY26
273
274
291
355
419
cps
424434
1. All dividend decisions are a matter for the Board at the conclusion of each reporting period. These align to the dividend policyand
are dependent on business and market conditions when each payment decision is made.
Dividend expectations
•Contact expects to lift the total dividend in FY27 to 42 cents per share.
1
‒On this basis, dividends in FY27-FY28 are expected to be imputed up to ~70%.
•Reliable ordinary dividends are expected to increase over time with growth in operating free cash flow.
Reflects 65% of FY26 operating free cash flow and 114% of the average operating free cash flow for the preceding four years
65%
648
40

22
Normalised and expected FY27 EBITDAF $1,045M
1
Assumptions based on mean hydrology and wind conditions
$299M$90/MWh3,335GWh
Strategic fixed
price
$367M$155/MWh2,370GWhCFDs
$335M$168/MWh1,995GWhC&I
$652M$171/MWh3,810GWhRetail
$116MOther income
4
$1,769M
-$0M$0/MWh5,850GWhHydro mean
-$11M$2.5/MWh4,635GWh
Geothermal
average
-$52M$178/MWh
5
291GWhThermal
-$102M$107/MWh950GWhRenewable PPAs
-$82M$193/MWh
6
x425GWhMarket acquired
-$247M
-$98MTransmission/Storage$56MLength
7
-$360MOpex BAU-$56MLocation losses
8
-$7MOpex –Integration costs
-$12MOpex –SaaS implementation cost
-$379MTotal Opex
-$477MTotal $0MTotal
* Fuel is natural gas, carbon and PPA costs.
2,324
46
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 FY27
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
=
=
=
=
=
=
1,895
100
3,810
3,335
CFDs
C&I
Retail
Strategicfixed
$155/
MWh
$168/
MWh
$171/
MWh**
ContractedUncontracted
1,769
-247
-98
-360
0
1,045
-19
x
53
48
42
38
55
107
116116
152152152
42
40
35
45
80
94
135
68
50
Aug-
26
Sep-
26
Oct-
26
Nov-
26
31
Dec-
26
Jan-
27
Feb-
27
Mar-
27
Apr-
27
May-
27
Jun-
27
ASX Futures, $/MWh
At 23 Jul 2026
$90/
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).| 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, irrigation and other
income. | 5. Gas price of $15/GJ, carbon price of $59/unit and thermal portfolio heat rate (9.8GJ/MWh). | 6. Acquired generation price includes premiums paid for HFO and NZAS demand response. | 7. Length of 557GWh assumed. | 8.
Locational losses of 5.6% on spot purchases and settlement of CFDs sold at a wholesale price of $87/MWh.
=
Trading delivers value to
largely offset locational losses
5
Digitalisation & continuous
improvement optimise fixed costs
6
Opex(BAU)
$M
** Retail volume contracted. Competitive risk remains on pricing achieved.Note: All figures are subject to rounding.
GWh:
=
=
Integration & Saas
implementation

23
Strategy
update

​Empowered
people and leaders
​Unite our people behind
Contact31+ and develop NZ’s
best energy leaders
​Relationships with
our stakeholders
​Maintain enduring trust with
stakeholders, investing for secure, affordable
renewable energy while upholding our
environmental commitment
​Productivity
​Drive disciplined growth by
simplifying processes and
deploying automation
​Tech advantage
​Establish a distinctive edge in
data and AI on a simplified and
secure technology platform
​Extend our advantage as
NZ’s geothermal leader
​Scale on high-quality existing fields,
explore new options, and continue to
improve our cost-leadership position​
​Build into new demand
with wind and solar
​Deliver lowest-cost diversified wind
and rapidly deploy solar, anchored on
long-term industrial partnerships​
​Lead the energy
transition at home
​Empower our customers to shift
energy use, while making every
interaction easy and personal
​Lead on new flexibility in NZ
​Accelerate batteries, build advantage in
hydro flex and maintain gas flex,
optimising our portfolio in real time​​
​Strategic pillars
​Leading New Zealand’s renewable energy future
​Values
Performance edge​Own the future​Brave humility
Underpinned by continued operational excellence across our diverse and resilient portfolio
​Enablers
24

25
Contact31+ is anchored on building renewables in
connection with long-term industrial partnerships
Data Centres
Metals
Electrification of dairy
Opportunities for new electricity demand exist at scale across key sectors
Tangata whenua
relationships
Environmental
stewardship
Grid / network
connectivity
Fuel flexibility
management
Local government
engagement
Sustainable business
practices
Planning and project
governance
Energy firming and
resilience
Community
involvement
Consenting
processes
Local contracting
relationships
Flexible load
contracting
Dairy decarbonisation could see
1.8 –4.6TWh
2
of new demand
Opportunities totalling 4 –6TWh
1
from
existing and proposed sites
Announced metals projects could add
>600GWh
3
of new demand
Enabling capabilities:
Contact can draw on its deep set of enabling capabilities to support customer energy transition and growth
1. Based on ~185MW total capacity at existing sites, with ~15% average 2025 utilisationestimated, and the disclosed, uncommitted pipeline capacity across major existing and potential large operators. | 2. Includes
known and committed biomass and electricity conversions. Upper bound is based on manufacturing and fuel use disclosure in Fonterra’s FY25 Climate Statement. Suitability for electrification to be confirmed. It is
expected a portion of load from shifting dairy manufacturing away from coal will go to biomass. | 3. Includes NZ Steel’s Electric Arc Furnace and the potential reopening of NZAS Line 4 potline. The consented
National Green Steel EAF presents further upside.

26
Total uncommitted generation pipeline of 11TWh+,
provides optionality to meet demand as it materialises
We are advancing 4TWh+ of development options, to be
anchored on long-term industrial partnerships
Huriwaka
250MW | 890GWh
Southland wind
>325MW | 1,210GWh
Te Mihi Stage 3
Up to 100MW | 830GWh
1
(Up to ~300GWh net uplift)
2
Tauhara 2
50 –70MW | 415 –580GWh
Stratford BESS
200MW | 400MWh
Argyle
80MWac | 180GWh
Stratford Solar (hybrid)
150MWac | 312GWh
1. Ultimatesize is subject to additional consented mass-take. | 2. Represents potential net uplift in output after accounting for the planned closure of the Wairakei geothermal station. | 3. Fluidtake is partially
consented. Ultimate size is dependent on additional land access and consented mass-take. |4. TeMihi Stage 3 is included on a net uplift basis.
Consent granted
In Fast-Track
Contact31+ priority
development options,
representing ~4TWh of
net new renewable output
And can draw additional projects from our 11TWh+ total pipeline as customer needs evolve
Tauhara 3
Up to 100MW | 830GWh
3
High priority proposed
Contact31+ growth
projects subject to FID
Future development
pipeline options
under assessment
​11
Solar
Geothermal
4
Wind
0.5
0.7
​Renewable generation development pipeline options, TWh
​4
​7
​7TWh
​4TWh

27
A pathway is in place for NZAS to act as long-term customer
underpinning Contact’s 1TWh+ Southland Wind Farm
Electricity stats
Up to
55 Turbines
>325MW
total capacity
Average annual output expected to be
>1,210GWh
Non-binding letter of intent (LOI) signed with Rio Tinto for a PPA to
support the potential restart of 50MW Line 4 potline at NZAS.
Consent approved April 2026.
Specialised infrastructure
advisor, Mafic, appointed to run
identification and selection
process for a strategic partner for
Contact’s extensive wind pipeline.
We have engaged a shortlist of credible wind partners.
Project updates
Contact is advancing strategic partner identification and targeting mid-2027 for Final Investment Decision

28
High-capacity fibre connection
Solar and battery development options
Available transmission capacity
Diverse high-capacity fibre,
both terrestrial and subsea,
provides connection to
Auckland where New
Zealand’s international
cables land.
350MW transmission capacity
available within 1-2 years with
minimal substation work.
600MW expected to be
available within 2-3 years
following planned upgrades.
3
150MWac / 312GWh p.a. solar
farm in consenting, with DC
coupled batteries potentially
providing up to 750MWh
storage.
2
500MW grid-scale battery
capacity consented.
Land owned and under option
Existing site complemented
by significant adjacent land
options.
Able to support scalable
renewable and load growth
opportunities.
Long-term member of the community
50 years operating in the
Stratford community.
Long-standing relationships
with local stakeholders
including councils and
tangatawhenua.
1. IT / compute load of 250MW. Approximately 350MW total load including ancillary load at peak times (subject to final design). | 2. Based on batteries with 5-hour duration. | 3. BCG analysis based on Transpower
data and disclosures.
Following the March 2026 closure of Contact’s Taranaki Combined Cycle baseload gas plant (TCC), Contact is taking steps
to leverage the unique combination of site resources and support growth in the Taranaki region
Contact and CDC will seek resource consent for a 250MW data centre
1
. It would be supported by co-located battery
storage development. Current activities focus on consenting, site and infrastructure design, customer engagement
and development planning.
Contact has partnered with CDC to explore data centre
development at its highly strategic Stratford site
Existing generation
The operation of Contact’s
existing 200MW fast-start
gas peaking assets at
Stratford is not impacted
by the data centre concept.
.

29
​Extend our advantage
as New Zealand’s geothermal leader
​Build into new demand with
wind and solar
​Lead the energy transition at home
​Lead on new flexibility in
​New Zealand
​Strategic pillars
​FY27 pillar targets
•Te Mihi Stage 2 on track (for delivery FY28)
•Tauhara 2 FID taken
1
•Tauhara 3 option progressed
•0.5TWh industrial energy demand electrified
•Kōwhai Park solar delivered
•FID on 1-2 additional solar farms
1
•1+ wind farms consented
•Glenbrook-Ohurua100MW battery delivered
•Additional 200MW battery under construction
•Manawa portfolio benefits of $10-20M p.a. delivered
•Future technology stack selected and execution commenced
•Cost-to-serve $135 per customer
2
•15 –20MW retail demand flex under management
Benefits of
productivity
programme clear
Manawa
benefits
delivered
42cps
dividend in
FY27
3
​FY27 financial targets
1. Each FID to be considered in isolation with all information available at the time. Pending appropriate market conditions and projects meeting returns thresholds. | 2. Cost-to-serve per customer (real 2026). Target
rebaselined to include all direct and indirect retail opex other than cost to acquire (previous method did not include all indirect costs allocated from corporate). Will be measured excluding any SaaS implementation
costs associated with investment in future retail platform. This differs from $/connection previously measured under Contact26. | 3.All future dividend decisions are at the discretion of the Board at the time.
What you can expect from us in the next 12 months
We have already accelerated the delivery on a number of our FY27 Contact31+ strategy pillar targets
Accelerated / early (FY26) delivery

30
Questions

31
Supporting
materials
Market update

32
National electricity demand
Source: EMI, Contact.
Does not include NZAS.
National electricity demand, TWh
Regional
change, %
FY26vs FY25
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 up ~3% (up ~1% normalised for NZAS demand response)
National electricity demand in FY26 was up ~3%
year-on-year to 42TWh. Adjusting for NZAS
demand response –called by Meridian in 1H25
to support challenging hydro conditions –
demand was up ~1%.
Demand at the Central North Island node was
down 15% due to the impact of the Winstone
Karioi pulp mill and Tangiwai sawmill closures
in August 2024, reflecting broader challenges in
wood and paper processing without the
protection of fixed price electricity hedging.
Huntly node demand increased 7% in FY26, due
to population growth in the Waikato/Hamilton
region and increasing electricity use from
electrification and industrial customers.
Seasonal conditions at irrigation nodes, along
with population growth, have resulted in a 4%
increase in demand in South Canterbury.
Southland demand growth appears to be
driven by ongoing industrial electrification,
particularly in the dairy and meat processing
sectors, alongside broader regional growth.
0%
7%
1%
4%
0%
(0%)
(2%)
0%
8%*
4%
0%
1%
(15%)
1%
3%
1%
4%
1%
5.1
4.9
5.0
5.0
5.0
4.2
5.0
10.3
10.6
10.2
10.5
11.2
10.9
11.1
25.8
26.1
25.8
25.6
25.9
25.7
25.9
FY20FY21FY22FY23FY24FY25FY26
41.2
41.6
41.1
41.1
42.1
40.9
42.0
+2%
+3%
North IslandSouth Island (ex NZAS)NZAS
3%

33
Hydro generation was up ~15% on
FY25, driven by high inflows from
Q2 FY26.
Impacts included:
•
The lowest thermal generation
share since the introduction of
the market (~6%).
•
Lower spot wholesale prices
than in FY25.
•
Lower total industry carbon
emissions.
Geothermal generation volume
was up ~6% with the addition of
TOPP 2 and Ngā Tamariki OEC5 in
2H26 and a full operational period
of Te Huka 3.
Solar increased from 17GWh to
~270GWh, ~0.7% of total market
generation.
Battery storage discharged
~40GWh during the period.
2
Generation by type, TWh
•FY26 began with storage levels close to the post-market average before a short dry spell saw levels draw
down over winter. Hydro storage reached its lowest level in August 2025, some 0.5TWh higher than the
lowest point in August 2024.
•Strong inflows from September drove a rapid recovery, with storage peaking in December 2025.
•Drier conditions followed through the second half of the year, although storage remained above
historical averages for the remainder of the period, closing with national hydro storage 135% of post-
market mean.
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
Jul-
24
Dec-
24
Jul-
25
Dec-
25
Jun-
26
1H251H26
National hydro storage, TWh
Carbon
emissions (mT)
Source: EMI (generation data), MBIE (emissions data, Electricity data tables) and NZX Hydro data.
1. Carbon emissions for FY26 Apr-Jun quarter have been estimated using historic conversion rates with actual generation data. | 2. Battery storage discharge is not included in total generation numbers.
Record renewable period
Fuel supply
High hydro inflows and new renewable generation online pushed thermal generation market share to its lowest since the market wasintroduced
2H262H25
2.9
2.7
2.9
0.3
3.5
3.7
3.8
7.6
9.0
9.6
23.9
21.4
24.7
2.4
1.7
0.5
3.9
4.2
2.3
FY24FY25FY26
Gas
Coal
Hydro
Geothermal
Wind
Solar
Non-identified
44.1
42.9
44.0
2.1
1
4.2
4.1
MeanActual

34
The market is responding to record investment in
renewable generation and actions to reduce dry year risk
Wholesale and futures electricity pricing, $/MWh
Source:EMI wholesale pricing, OTA, to 30 June 2026.
0
50
100
150
200
250
300
350
400
450
Jun-
17
Jun-
18
Jun-
19
Jun-
20
Jun-
21
Jun-
22
Jun-
23
Jun-
24
Jun-
25
Jun-
26
Long-dated futures (>12 months)Short-dated futures (<12 months)Monthly average spot price
1. Change in ASX Settlement prices at Otahuhu for Q3 2026 from 31 Dec 2025 to 30 June 2026. Source: ASX.| 2. Company announcements and Contact’s analysis.| 3. 2025 real –Otahuhu Node OTA,
Auckland. This is a through-the-cycle measure in a balanced market. Prices achieved are a function of the market at a point in time.
Reliable, plentiful
natural gas
5 year average
spot price
=$139/MWh
10 year average
spot price
= $127/MWh
Gas outages & availability decline
•
Reduced thermal generation allowed more gas to
be stored in AGS, while Genesis replenished its coal
stockpile (backed by the HFO). As a result, short-
dated futures moved lower alongside spot prices,
responding to low risk of fuel scarcity in Winter
2026.
•
The low fuelling risk led to ASX settlement prices for
Q3 2026 falling >60% over 2H FY26
1
.
Short-term pricing (reflected in short-dated futures)
•
Long-dated futures declined 27% over 2H FY26,
reflecting an expectation that the market is largely
moving back into supply / demand balance.
•
~3TWh of generation either committed or under
construction and expected to come online by 2027
2
.
•
Contact expects the long-term wholesale price to
settle around $115-125/MWh
3
reflecting the marginal
costs of new renewable projects and the costs
associated with firming renewable intermittency.
Long-term pricing (reflected in long-dated futures)
•
Spot wholesale electricity prices fell sharply
following Winter 2025 as intense rainfall and high
wind conditions lifted renewable generation
volumes.
•
This displaced the need for thermal generation
(leading to the lowest thermal generation market
share since the introduction of the market).
•
These conditions led to the lowest recorded
monthly average spot price in January 2026
($4/MWh).
FY26 spot wholesale pricing
Wholesale market pricing

35
Retail electricity market connection trends
•
Retail competition remained active, with customer churn broadly
unchanged at ~19.5%.
•
Tier 1 retailers now hold ~86% market share. Growth over the last 2
years was led by Meridian (+12% over two years, excluding Flick),
followed by Contact (+6%) and Mercury (+3%).
•
Genesis’ decline has been driven by the closure of Frank Energy
(announced June 2025) and a shift to focus on margin quality over
raw customer numbers.
•
Tier 2 retailers held steady, while Nova fell by 9%. The ~41k
connection loss across Tier 2 retailers was largely driven by
Meridian’s acquisition of Flick Energy in May 2025.
•
Contact added 27k electricity connections over the past two years,
resulting in a 20% market share.
Change in retail customer electricity connections, ‘000s
30 June 2024 –30 June 2026
2yr % change2yr ICP delta (1000s)
Retail electricity tariff changes, c/ kWh
Tier 2: -41k connections
Retail pricing trends
•
Residential electricity prices have risen steadily, at a compound
annual growth rate of ~6% over the five years to March 2026.
•
Average prices increased ~11% in the year to March 2026, reaching
38.3 c/kWh.
•
The lines component rose 13%, while the energy and other
component increased 10%.
•
Cost pressures on the lines component of the tariff are expected to
remain as the increased cost of transmission and distribution
infrastructure continues to be incurred.
2
•
Moderating wholesale prices are expected to lower the electricity
component over time.
12 months
ended:
Tier 1: +93k connections
Source: EMI –residential ICPs only
Source: MBIE
18.6
19.5
20.7
20.9
23.0
11.6
12.0
12.4
13.5
15.3
Mar-22Mar-23Mar-24Mar-25Mar-26
30.2
31.5
33.1
34.4
38.3
+6%
Competition remains strong as Tier 1 retailers extend market
share leadership
Retail electricity market
Lines (c/kWh)Energy & Other (c/kWh)
1
1. Compound annual growth rate. | 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). Costs are increasing annually.
6%
3%
24%
-9%
2%
3%
1%
11%
-30
-20
-10
0
10
20
90
-40
-6%
GenesisMercuryMeridianNovaPulseElectric Kiwi2Degrees/
Vocus
OtherContact
Breakdown of an average household
electricity bill
38.5%
8.0%
24.5%
11.0%
13.0%
4.5%
0.5%
Generation
Transmission
Distribution
Metering
Retail
GST
Levies
Source: Electricity Authority

36
Supporting
materials
Financial results

37
Guidance topics
FY27 Guidance CommentaryFY27 guidance
FY26
result
FY26 guidance
1
$375M -$385M$387M$385M -$395M
Other operating costs
$360M$361M$360M
Other operating costs –BAU
2
Reflects costs of implementing new systems designated as SaaS, reduces SIB
capex, includes costs to FID for the Future Retail Platform.
$10M -$15M--
Other operating costs –SaaS
Non-recurring costs relating to the Manawa acquisition.$5M -$10M$26M$25M -$35M
Other operating costs –Manawa integration and
transaction
$178M -$188M$145M$170M -$185M
Stay in business (SIB) capex (cash)
$134M -$139M$82M$115M-$125M
SIB capital expenditure BAU
Completion of programme in FY26.-$14M$12M-$13M
SIB accelerated programme
Spend brought forward into FY26 with remainder expected in FY28. -$15M-
SIB capital expenditure Tauhara spare rotor
Completion of extension work activities to occur within FY27.~$17M$21M$20M-$25M
SIB capital expenditure Wairakei
Continued upgrade work on Highbank and Coleridge hydro sites. $7M -$12M$5M
$18M -$22M
SIB capital expenditure Manawa refurbishment
Decommissioning relating to TCC and Wairakei. ~$5M$1M
SIB capital expenditure decommissioning provisions
-$5M
SIB capital expenditure Geothermal Wells
Completion of system integration from Manawa transaction. ~$15M$2M
SIB capital expenditure integration
Te Mihi Stage 2, Glenbrook-Ohurua Battery 2 and pre-FID activity. $460M-$470M$375M$500M-$510M
Growth capital expenditure (cash)
3
Increase with Battery and Wairakei depreciation and increase in digital assets.$310M-$320M$294M$280M-$290M
Depreciation and amortisation
$120M-$130M$140M$115M -$125M
Net interest (accounting)
$100M-$110M$122M$105M-$115M
Cash interest(in operating cash flow)
FY27 lower tax due to benefits of investment boost policy and tax credit on
decommissioning of TCC.
$80M-$90M$119M$120M-$130M
Cashtaxation
Including (gains) / losses on ASX market making.$5M-$10M($4M)$5M-$10M
Realised (gains) / losses on market derivatives not in a hedge
relationship
Increase in the ordinary dividend to reflect benefits of the Manawa acquisition.42 cps40 cps40 cps
Target ordinary dividend per share
Increase due to impact of lower cash tax and higher capitalised interest due to Te
Mihi Stage 2 and Glenbrook-OhuruaBattery 2.
65 -70%64%~50%
Operating cash flow conversion
1. Updated at 1H26 results. | 2. Includes corporate costs (ex integration and transaction) of $69M in FY26 (vs. $60-70M guidance) and ~$65M in FY27 guidance. | 3. Growth capital expenditure includes capitalisedinterest.

38
$376M$95/MWh 3,960GWh
Strategic fixed
price
$264M$155/MWh1,700GWhCFDs
$289M$165/MWh1,750GWhC&I
$627M$164/MWh3,825GWhRetail
$100MOther income
4
$1,656M
-$0M$0/MWh5,750GWhHydro
-$20M$4/MWh4,950GWhGeothermal
-$59M$215/MWh
5
275GWhThermal⁴
-$83M$100/MWh830GWhRenewable PPAs
-$52M$260/MWh200GWhMarket acquired
6
-$214M
-$90MTransmission/Storage$139MLength
7
-$370MOperatingexpenses –BAU -$140MLocation losses
8
-$35MOpex -integration and transaction costs
-$405MTotal Opex
-$495MTotal-$1MTotal
FY26assumptions that deliver normalised & expected
EBITDAF of $945M over a financial year
Hydrology & asset availability
optimise generation
3
4
Total
x
=
Access to and price of fuel*
drives financials & risk position
Channel choices maximise
long term value
2
1
Net price
3
driven by
best commercial practices
2
Total
x
=
Trading delivers value
offsetting locational losses
5
Digitalisation & continuous
improvement optimise fixed costs
6
x
x
x
x
x
x
x
=
=
=
=
Normalised and expected EBITDAF assumptions
1
FY26 results
With reconciliation to actual performance
x
x
=
=
=
=
Normalised & ExpectedFY26 at start of year
Lower renewables
FY26 EBITDAF normalised for non-recurring
Manawa transaction and integration costs
Renewable generation below mean (-754GWh)
Calculated at thermal SRMC
Fixed costs
Transmission & storage costs were $18M lower than forecast,
supported by LCE rebates. Reclassification of $10M to fixed costs.
Integration & transaction costs were $9M lower than forecast.
Non-recurring Manawa related costs
Reported FY26 EBITDAF
132
25
94
34
36
26
8
945
1,011
1,037
Lower thermal heat rate due to final run of TCC and acquired
generation price lower than assumed (-$80/MWh)
Market channel price
Lower GWAP on merchant sales was more than offset by very low
location losses. Contact’s LWAP/GWAP spread reduced to ~1%
Lower sales volumes wereoffset by meeting sales with lower
thermal and more acquired generation at lower prices
Net volume impact
Increased long-term channel price
Retailnet price outperformed guidance
assumption by $10/MWh
=
Gas, carbon, acquired generation price
$M
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). | 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, broadband gross
margin, irrigation and other income. | 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 for FY26 assumed. | 8. Locational losses of 6.5% on spot purchases and settlement of CFDs sold at a wholesale price of $180/MWh.

39
57
76
100
939
-265
-291
-315
-346
-459
-85
-56
-74
-80
-185
-94
-269
-326
-256
​1,023
FY22FY23
​1,269
​53
FY24
​1,476
​50
FY25
​1,640
​-14
FY26
Electricity sales margin
Other gross margin
Fixed operating costs
Location losses
Variable fuel costs
546
573
663
774
1,011
Operating earnings (EBITDAF)
106
115
127
136
132
3.69
1.39
​FY22
3.73
1.42
​FY23
3.80
1.22
​FY24
3.69
1.73
​FY25
3.68
3.91
​FY26
5.08
5.14
5.02
5.42
7.58
RetailLong-term sales
117
126
116
200
138
1.13
0.39
FY22
0.52
0.15
FY23
1.62
0.59
FY24
1.09
0.46
FY25
0.23
0.68
0.83
FY26
1.52
0.67
2.20
1.55
1.74
ThermalAcquiredPPA Purchases
Electricity sales
Variable fuel costs
11111
3.94
3.28
FY22
3.92
3.19
FY23
3.63
3.39
FY24
3.30
4.54
FY25
5.03
4.91
0.01
FY26
7.22
7.10
7.02
7.84
9.96
HydroGeothermalBattery
(i) Renewables
(ii) Thermal, acquired and PPAs
133133
150
186
155
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
1.86
2.01
0.23
FY26
3.66
2.63
4.21
3.97
4.10
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 46for a definition and reconciliation of EBITDAF. EBITDAF figures are underlying i.e. excluding the impacts of the ($113M) AGS onerous contract provision expense in FY23, a $12Mnet movement in the AGS
provision in FY24, and a release of the AGS provision of $98M in FY25.
117
121
137
158
140
​8.739
​7.772
​9.232
​9.390
​11.687
Price
($/MWh)
Volume
(TWh)
Historic performance

40
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 expressed as absolute emissions reductions and measured
on a calendar-year basis.| 3. The target for Scope 3 emissions from use of sold products increased due to Contact’s role in supplying gas to essential All-of-Government public services.
FY26FY25FY24FY23FY22TargetUnitIndicator
317,255
740,468947,491526,621786,842
45% reduction of
2018 Scope 1 and 2
emissions by 2026,
equivalent to
647,443 tCO2e.
2
tCO2eDirect GHG emissions (Scope 1)
316,112
739,790947,131526,282786,544tCO2e-Stationary combustion (generation)
824
409332307297tCO2e-Mobile combustion
50​
11428321tCO2e-Fugitive emissions
269
155tCO2e-Stationary combustion (ancillary equipment)
2,460​
1,1839751,9571,399
tCO2eIndirect GHG emissions (Scope 2)
319,715
741,651948,466528,579788,241tCO2eSub-total Scope 1 and 2
390,731
369,583265,034273,673394,784tCO2eIndirect GHG emissions (Scope 3)
15,517​
8,7996,5226,1976,37134% reduction of
2018 Scope 3 GHG
emissions from use
of sold products by
2026, equivalent to
244,311 tCO2e.
2
45% reduction of
2018
Scope 1 and Scope 3
emissions from all
sold electricity by
2026, equivalent to
688,253 tCO2e.
2
tCO2e-Category 1 –Purchased goods and services
79,634​
87,20379,18588,26657,876tCO2e-Category 2 –Capital goods
4,251​
8,0065,1301,050149,743tCO2e-Category 3 –Fuel and energy
1
478​
205254108444
tCO2e-Category 4 –Upstream distribution and
transportation
93​
695847108tCO2e-Category 5 –Waste
1,720​
1,0811,6011,274567tCO2e-Category 6 –Business travel
2,044​
956927965832tCO2e-Category 7 –Employee commuting
267,348​
250,612170,929175,603178,554tCO2e-Category 11 –Use of sold products
3
8,678​
339429164289tCO2e-Category 13 –Downstream leased assets
11,979
12,313---tCO2e-Category 14 –Investments
711,456
1,111,2351,213,500802,2521,183,025tCO2eTotal Scope 1, 2 and 3 emissions

41
Growth capital expenditure
1. Excludes ~$0.6M of development capex that was incurred by Manawa prior to acquisition. | 2. Total under current board approvals. | 3. Additional funding was approved in FY26 to close out the Tauhara project including
replacement of pipework and acid dosing systems. | 4. For TeMihi Stage 2 at FID, 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 materialiseand to ensure prudent balance sheet management. If called on, this would take the total cost to $761M. | 5.
Relates primarily to deployment of demand flex technology and Clutha consenting. | 6. Solar covers both Kōwhai Park and Gloritinvestment and excludes pre-FID development expenses for solar which are captured
within receivables. Gloritobtained Financial Close during FY26.
Growth capital expenditure –cash basis, $M¹
Total²
Remaining under
current approvals
12 months ended
30 June 2026
Up to
30 June 2025
940827905Tauhara
3
305310292Te Huka 3
712305205201Te Mihi Stage 2
4
3861121Wind
163155691Glenbrook-Ohurua Battery 1
235207271Glenbrook-Ohurua Battery 2
392316-Tauhara Unit 2
211219Other
5
33511721196Capitalised interest
2,7896863751,727Total
Contact’s FY26 growth investment demonstrates progress in the strategic execution of its renewable development pipeline
Project status
•
Construction commenced in FY25 on three major renewable projects:
Glenbrook-OhuruaBattery 1, Kōwhai Park solar and TeMihi Stage 2
geothermal. Contact’s firstbattery is now operational, with final costs and
close out activities to come.
•
Construction of Glenbrook-OhuruaBattery 2 commenced during FY26
and Notice to Proceed was issued to the EPC contractor for Gloritsolar.
•
Construction of the Tauhara and TeHuka 3 geothermal plants is now
complete, with remaining spend relating to final close out activities.
•
Tauhara 2 is now in the Select stage as well as pre-FID drilling works.
•
Contact does not currently have any wind projects under construction.
The reported wind development spend reflects pre-FID activity only.
Total²
Remaining under
current approvals
12 months ended
30 June 2026
Up to
30 June 2025
866322-Solar
6
9216CO
2
840183Forestry
179652489Total
Investment in joint ventures and associates, $M
FY26 results: Cash flow
Financial treatment
•
For major growth projects, Contact capitalisesinterest from the point of
FID—or from the commencement of significant pre-FID works—through
to commissioning. The capitalisationrate reflects the average interest rate
across the portfolio.
•
Contact’s investments in the Kōwhai Park solar farm and Gloritsolar farm
are accounted for as investments in joint ventures and associates, and are
therefore excluded from growth capital expenditure.

42
Output from Contact generation and renewable PPAs sold to the national grid, GWh
Generation and sales position
3,333
3,114
3,283
3,185
3,388
4,543
4,914
3,752
3,698
3,940
3,919
3,628
3,297
5,032
1,360
1,592
1,046
1,620
1,088
229
FY20FY21FY22FY23FY24FY25
11
827
FY26
8,445
8,404
8,269
7,543
8,636
8,928
11,013
439
Operational data
Renewable %
84%81%
87%
98%
94%
81%88%
Geothermal generation, GWh
FY26 geothermal generation was 371GWh higher than FY25. A full period of generation Te Huka 3 was
partially offset by statutory outages at Te Huka 3, Tauhara and Wairakei.
1,415
1,240
1,386
1,380
376
1,045
1,081
1,055
998
1,405
1,255
1,261
335
339
331
308
1,064
1,287
1,384
340
299
322
323
274
986
1,062
198
155
189
176
316
300
309
203
277
316
210
206
FY20FY21FY22FY23
127
FY24
229
FY25FY26
3,333
3,114
3,283
3,185
3,388
4,543
4,914
Hydro generation, GWh
Thermal generation, GWh
871
1,126
673
164
1,395
692
147
291
234
179
148
223
378
195
213
190
125
78
3
79
FY20
18
81
FY21
4
81
FY22
2
FY23
1
FY24
18
FY25
0
81
FY26
1,439
1,673
1,127
517
1,620
1,088
229
Thermal generation was 859GWh lower than FY25 due to high hydro inflows and additional
renewable generation brought online in the last 18 months displacing both Contact, and the
market’s, need for thermal generation outside of winter 2025. Following the closure of TCC, Contact’s
mean expected thermal volume is now 250 –300GWh p.a.
Te Huka
Ōhaaki
Poihipi
Wairakei
Te Mihi
Tauhara
Te Huka 3
Whirinaki
Te Rapa -direct
Te Rapa -spot
Stratford Peakers
TCC
BatteryRenewable PPAsThermalHydroGeothermal
1,657
1,667
1,775
1,740
1,594
1,445
1,480
2,095
2,031
2,165
2,179
2,034
1,852
1,979
669
904
FY20FY21FY22FY23FY24FY25FY26
3,752
3,698
3,940
3,919
3,628
3,297
5,032
North Island
South Island -ex Clyde & Rox
Clyde
Roxburgh

43
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
100%
90
FY20
98%
87
FY21
100%
89
FY22
98%
FY23
100%
91
FY24
95%
87
FY25
97%
89
FY26
89
+4%
31.1
30.5
31.0
30.4
29.2
29.7
29.9
FY20FY21FY22FY23FY24FY25FY26
+1%
Geothermal fuel performance
Taranaki combined cycle (TCC)
Hydro
Geothermal
2
Stratford Peakers
Plant availability
1
1. Availability Factor calculation includes all station outages (Planned, Maintenance, Forced) but not plant deratings. | 2.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. | 3. 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.
Excludes impact of reduced Wairakei field output in FY27 associated with Wairakei station decommissioning and switchover to Te Mihi Stage 2.
Diesel Peakers
Despite a planned outage at Wairakei in FY26, total mass extracted,
and extracted volumes as a % of consented mass take, were up on
FY25 (which included a planned outage (25 days) at Te Mihi and an
electrical outage at Wairakei A&B station).
Upcoming geothermal statutory turnarounds (outages)
3
Frequency & typeFYImpact
(GWh)
Plant
4y Stat Turnaround2716
Te Huka 1&2
4y Stat turnaround + ext works27320Wairakei
4y Stat turnaround2831Poihipi
Y1 Stat Turnaround2873Te Mihi Stage 2
Y3 Stat Turnaround28169
Tauhara
Y3 Stat Turnaround2857
Te Huka 3
4y Stat turnaround29158Te Mihi
Pool revenueElectricity
Output,
GWh
Capacity
factor
AvailabilityNet
capacity
MW
$M$/MWh
12118067320%84%377FY22
181071645%85%377FY23
2571841,39542%82%377FY24
22933069221%89%377FY25
271831479%93%377FY26
Pool revenueElectricity
Output,
GWh
Capacity
factor
AvailabilityNet
capacity
MW
$M$/MWh
4781213,94057%83%784FY22
290743,91957%84%784FY23
5941643,62853%90%784FY24
5381633,29748%87%784FY25
410815,03240%78%1,295FY26
Pool revenueElectricity
output
GWh
Capacity
factor
AvailabilityNet
capacity
MW
$M$/MWh
4581403,28391%97%425FY22
254803,18589%94%410FY23
6011773,38889%94%586FY24
8451864,54384%90%649FY25
360734,91488%92%649FY26
Pool revenueElectricity
Output,
GWh
Capacity
factor
AvailabilityNet
capacity
MW
$M$/MWh
3821217910%53%202FY22
312071488%77%202FY23
3917522312%50%202FY24
8221737822%70%202FY25
10122814%85%202FY26
Pool revenueElectricity
Output,
GWh
Capacity
factor
AvailabilityNet
capacity
MW
$M$/MWh
259740%95%158FY22
1.249120%82%158FY23
1.168710%97%158FY24
12661181%92%158FY25
0.112200%95%167FY26
Operational data

44
Hawea storage,GWh
Gas storage, PJ
Closing storage
Closing storage (current)
Fuel storage movements
Source: NZX Hydro data
113
252
188
141
85
263
160
275
322
265
242
232
330
174
377
252
-183
-326
-291
-286
-151
-278
-263
-265
1H232H231H242H241H252H251H262H26
Inflows
Opening storage
Releases
253
191
139
87
264
160
275
261
4.7
2.4
3.4
2.8
1.6
3.4
3.3
3.9
2.7
1.7
0.9
1.3
3.1
1.9
2.1
0.9
-0.7
-0.7
-1.5
-2.5
-1.3
-2.0
-1.6
-0.9
-4.3
1H232H231H242H241H252H251H262H26
Gas Injected
Gas Extracted
Opening Storage
2.4
3.4
2.8
1.6
3.4
3.3
3.9
3.8
Operational data
4
Balance
classified as
long term
storage (PJ)
44
44444
Transferred to long-term storage

45
Contracted gas volumes,PJ
Uses of gas, PJ
Gas storage monthly injections and extractions, PJ
Contracted and stored gas
Gas injectedGas extracted
5.4
5.9
6.5
7.0
5.4
3.0
3.03.0
2.2
5.0
3.0
2.6
2.2
2.8
2.8
2.8
3.8
0.2
CY26
1
CY27
CY28
CY29
CY30
CY31
CY32
CY33
CY34
CY35
2
9.0
8.4
8.5
8.6
9.7
8.1
5.8
Aug-
25
-0.13
0.24
Sep-
25
-0.50
0.00
Oct-
25
-0.76
0.01
Nov-
25
-0.61
0.02
Dec-
25
0.99
0.27
Jan-
26
-0.05
-0.08
0.17
Feb-
26
-0.14
0.03
0.29
Mar-
26
0.00
Jul-
25
0.26
Apr-
26
-0.32
0.01
-0.17
May-
26
-0.17
0.20
Jun-
26
-0.02
16.1
15.1
15.5
8.8
-3.0
1.9
-1.6
-6.1
-13.0
-9.2
-2.0
-2.8
-2.5
-2.2
-4.3
-4.2
-1.5
-2.6
-2.0
FY23FY24FY25
-0.5
FY26
Net extraction (injection)
Generation
Customer sales
Wholesale sales
Purchases
Operational data
1.CY26reflectsactualvolumesandforecastsforthesecondhalfoftheyear.|2.CY26-CY35reflectsthemaximumvolumeofgasavailableundercontracts.
Short-term gasGreymouthPohokura

46
EBITDAF is Contact’s earnings before interest, tax, depreciation and amortisation, asset impairment
and write-offs, and changes in fair value of financial instruments.
EBITDAF is commonly used in the electricity industry so provides a comparable measure of Contact’s
performance.
Reconciliation of statutory profit back to EBITDAF:
Variance onprior
year
12 months
ended
30 June 2026
12 months ended
30 June 2025
%$M
Against underlying
1
ReportedReportedUnderlying
1
62%
162
423331261Profit
7%
21
294273
Depreciation and
amortisation
na
(56)
(21)35
Change in fair valueof
financial instruments
40%
40
140100 Net interest expense
60%
62
166132104Tax expense
800%
8
91
Asset impairment / write-
offs
31%
237
1,011872774EBITDAF
Reconciliation between Profit and EBITDAF
The movements between FY26 and FY25 underlying profit are
as follows:
•Depreciation and amortisation: increased by $21M as a
result of an increase in fixed assets from the purchase of
Manawa and a full year of TeHuka 3 depreciation. This has
been partially offset by significantly lower usage of thermal
assets compared to FY25.
•Net interest expense:higher than FY25 as a result of
additional borrowing to complete the Manawa acquisition
and interest no longer being capitalised on TeHuka 3.
•Tax expense:increased by $62M due to the tax impact of
higher operating earnings.
•Asset impairment / write offs: Assetwrite offs related to
equipment replaced during first Tauhara outage (inclusive
of pipework upgrade) and inventory related to TCC post
decommissioning.
Non-GAAP profit measure
1. All variances and commentary reflect movements in underlying performance. In FY25, reported results include a release of the AGSonerous contract provision of $98M pre-tax ($71M after tax). Underlying performance
excludes the impact of the provision release.

47
S&P Net Debt / EBITDAF ratio
FY26FY25FY24FY23FY22$M
Estimated
Actuals from S&P ratings report
Net Debt
3,0512,4491,9131,5561,099
Carrying value of borrowings
(90)(94)(41)(43)(55)
Fair value adjustments
18116514212053
Restoration and environmental provisions net
of tax
(238)(238)(113)(113)(113)
Hybrid bond credits
1
(766)(514)(146)(89)(4)
Accessible cash
2
2,1381,7681,7631,431980
S&P Adjusted Net Debt
EBITDAF
1,011774663573546
Reported EBITDAF (underlying)
-(15)---
Utilised AGS provision released
(3)(13)(6)(27)(9)
Realised gains/losses on market derivatives
75444
Share based compensation
1411---
Transaction costs related to the Manawa
acquisition
1,029762661551541
S&P Adjusted EBITDAF
2.12.32.72.61.8
Net debt/EBITDAF (x)
1. 50% equity credit for capital bonds. | 2. Cash less restricted cash held by Macquarie for ASX prudential.
•These calculations have been
provided as an illustration of
the adjustments made by
Contact’s ratings agency, S&P
Global, when assessing
Contact’s Net Debt/EBITDAF
ratio.
•Net Debt has been adjusted
from the financial statements
to include certain long-term
liabilities where S&P considers
these to have debt-like
characteristics.
•Adjusted EBITDAF reflects
S&P’s view of core operating
items (unrelated to investing
and financing).
S&P adjustments

48
Reconciliation of change in fair value of financial
instruments
DescriptionChangeFY25FY26
Realised /
unrealised
Change in fair value offinancial instruments $M
Realised gains or losses on the settlement of
electricity derivatives entered into to meet Contact’s
market making obligations
17(13)4
Realised(A) Net market making
Mark-to-market of open electricity derivatives in
future periods
224
Unrealised
Market making
NPV of the changes to the forecast forward
wholesale price path vs the wholesale path when
the contracts were agreed
(70)(7)(77)
NZAS long-term sale CFD
37(13)24
Kōwhai Park acquired PPA
66-66
Mercury CFD (Manawa)
Mark-to-market of open electricity / interest rate
derivatives in future periods
9(4)5
Other non-hedged movements
Contact recognises a share of the profit that joint
ventures make in the Income Statement. This is the
amount within their profit that relates to the joint
venture’s unrealised derivative movements.
(5)-(5)
Share of unrealised gains/(losses) from joint
ventures
39(22)17
Unrealised
(B) Unrealised movements in non-hedge effective
electricity derivatives
56(35)21
Realised
and
unrealised
Total change in fair value offinancial instruments
as per segment note (A+B)
Commercial hedges recognised in EBITDAF that do not qualify for hedge accounting
Financial contracts that hedge portfolio sales that
are settled in the period
(10)(5)(15)
Realised
Financial Transmission Rights (FTR) settlements
and Exchange for Physical (ASX)
Realised settlement (difference between the fixed
contract and spot settlement)
92(134)(42)
Net settlement of NZAS and Mercury contracts in
the period
5-5
Reclass share of unrealised gains/(losses) from joint
ventures to Statement of Comprehensive Income
143(174)(31)
Change in fair value of financial instruments as
per Income Statement
In the period, Contact acquired Manawa
Energy and all of its associated long-term
sales contracts. This included several major
contracts for difference (CFD) that are not
eligible for hedge accounting. The most
significant of these is the sale of electricity
to Mercury Energy.
As with Contact’s existing CFDs ineligible
for hedge accounting, movements in
expected wholesale prices, when
compared to forward wholesale prices
when the contracts were entered into,
drive changes in their recorded fair value.
These non-cash movements, which relate
to future periods, are recognised in the
current period in the change in fair value
of financial instruments line item. These
movements increase the volatility of
Contact’s reported Net Profit After Tax.
Fair value of financial instruments

49
Historical financial information
FY26
FY25FY24FY23
FY22Unit
ReportedUnderlying
2
ReportedUnderlying
2
ReportedUnderlying
2
3,2063,3062,8672,1182,387
$MRevenue
1
2,1952,4342,5322,1922,2041,6131,5001,820
$MExpenses
1
1,011872774675663460573546
$MEBITDAF
423331261235230127211182
$MProfit
648434424282330
$MOperating free cash flow
64.054.453.936.042.4
cpsOperating free cash flow per share
4039373535
cpsDividends declared
10,6616,8136,2085,8085,166
$MTotal assets
5,4324,0533,5893,0042,326
$MTotal liabilities
5,2292,7602,6192,8042,840
$MTotal equity
3747423628
%Gearing ratio
3
Historic performance
1.Revenue and expense figures align with the treatment of realised movements in financial instruments within the segment note of the financial statements. | 2.In FY23 Contact recognised a net onerous contract
provision expense for AGS of ($113M) within EBITDAF and ($84M) within profit. In FY24 Contact recognised a net movement in the AGS onerous contract provision of $12M within EBITDAF and $5M within profit. In
FY25, the release of the AGS onerous contract provision increased reported EBITDAF by $98M and profit by $71M. Underlying performance excludes these impacts. | 3. Gearing ratio is calculated as: Senior debt -
including finance lease liabilities / (Senior debt -including finance lease liabilities + Equity).
Note:From FY24 Contact no longer reports impairments and write-offs within EBITDAF. These are now reported separately to better reflect underlying performance. FY24 EBITDAF is stated excluding $50M of
write-offs and impairments. Previous years have not been restated (FY22 includes a $1.5M peaker write-off).

50
FY26FY25
Year ended 30 June 2026Year ended 30 June 2025
GWAPVolumeGWAPVolume
$M$/MWhGWh$M$/MWhGWhNote: this table has not been rounded andmight not add
657179 3,675601163 3,689Electricity sales to Retail segment
3311512,189208 1331,566Electricity sales to C&I (netback)
1,270920CfDs –Tiwai support sales
677411Tauhara PPAs
1,517-CfDs –Mercury
1
507394CfDs –Other Long term sales
1,6181,903CfDs and ASX -Short term sales
637114 5,589569157 3,629Electricity sales –CfDs
1,62414211,4541,3771558,883 Total contracted electricity sales
5 202475 21 229 Steam sales
2314Other income
2(12)Net income on gas sales
11-Irrigation net income
11Net income on electricity related services
374Net other income
1,66614211,701 1,386 1529,112 Total contracted revenue
(323)(32)10,175(389)(44)8,928Generation costs
2
(203)(134)1,512(122)(264)462 Acquired generation cost
(526)(45)11,687(511)(54)9,390Generation costs (including acquired generation)
824 8110,1861,742 1958,928Spot electricity revenue
117771,512 116252462 Settlement on acquired generation
9418011,6981,8581989,390 Spot revenue and settlement on acquired generation (GWAP)
(509)(87)(5,875)(1,143)(218)(5,255)Spot electricity cost
(427)(76)(5,589)(695)(191)(3,629)Settlement on CFDs sold
(936)(82)(11,464)(1,838)(207)(8,883)Spot purchases and settlement on CfDs sold (LWAP)
523420507 Trading, merchant revenue and losses
1,145895Wholesale EBITDAF
2
-98Onerous contract provision unwind
1,145994Wholesale EBITDAF reported
Wholesale segment
Segmental performance
1. Mercury volume included from 11 July 2025 (completion of Manawa acquisition). | 2. FY25 EBITDAF (underlying) excludes the release of the AGS onerous contract provision equated to
$98M.