Contact Energy performance supports renewable investment

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



19 August 2024

Contact Energy performance supports
renewable investment


Twelve months ended
30 June 2024
FY24
Twelve months ended
30 June 2023
FY23

Underlying
i
Reported Against underlying
EBITDAF
ii
$663m $675m ↑ 16% from $573m
Profit $230m

$235m ↑ 9% from $211m
Profit per share 29.1 cps

29.9 cps ↑ 8% from 26.9 cps
Operating free cash flow
iii
$470m ↑ 67% from $282m
Stay-in-business capital expenditure (cash) $110m ↓ 3% from $113m
Growth capital expenditure (cash) $470m ↓ 0% from $472m
Key strategic highlights
• Tauhara geothermal station online since May 2024. Final commissioning underway.
• Te Huka 3 geothermal station now in commissioning. Expected online in Q4 2024.
• New long-term agreement to supply renewable electricity to NZAS.
• Construction started on 100MW grid-scale battery at Glenbrook, expected online Q1 2026.
• Confirmed investment in 168MWp Kowhai Park solar farm, expected online in Q2 2026.
Financial performance
Contact Energy has reported net profit of $235m in FY24 and operating earnings (EBITDAF)
of $675m. Reported figures include a net movement in the onerous contract provision
relating to the Ahuroa Gas Storage facility (AGS) of $12m within EBITDAF ($5m within net
profit after tax and interest). Excluding the movement in the provision, underlying net profit
was up 9% on FY23 to $230m and EBITDAF was up 16% to $663m.
The improved operating result was driven by closer alignment of channel pricing to the
wholesale market and greater thermal efficiency, partially offset by lower hydro generation,
and reduced steam revenue following the closure of Te Rapa. Net profit was impacted by
one-off write-offs of $36m after tax relating to damage to peaker assets, remediation work
required at the Tauhara geothermal plant and software projects not continuing as planned.
Hydro volatility characterised operating conditions throughout the period and gas supply
tightened, with flow-on impacts to wholesale pricing from more thermal generation. Contact
increased contracted sales volumes in anticipation of Tauhara coming online and with its
delay to mid-2024 met this sales position through a balance of additional thermal and
acquired generation. At the same time, Contact has executed well on its channel mix and
pricing strategies.

Contact Energy Ltd
2
“The result has been a demonstration of strength in our underlying performance as we
managed through market volatility, while keeping the momentum to deliver existing and new
renewable developments,” says Chief Executive Mike Fuge.
Operating free cash flow of $470m was up 67% on the prior year on the improved operating
result, relatively lower levels of working capital due to higher thermal generation and
reflecting the continued capitalisation of interest on Tauhara borrowings. In FY24, growth
capital expenditure was $470 million as Contact invested twice its net profit for the year into
renewable development.
The Board declared a final dividend of 23 cents per share, taking the annual dividend
declared for FY24 to 37 cents per share. Shareholders will have the option to participate in
Contact’s dividend reinvestment plan at a 2% discount.
Demand
In May 2024, Contact entered into a new long-term agreement with the New Zealand
Aluminium Smelter (NZAS) to supply renewable energy to its Tiwai Point operation in
Southland. Under the agreement, Contact has been provided with demand response of up to
46MW, with the mechanism activated at maximum capacity in July 2024 to support New
Zealand’s security of supply.
“This new long-term agreement de-risks investment in new renewable generation,
contributes to energy security and helps to preserve an important export industry, supporting
growth and decarbonisation of the New Zealand economy,” said Mr Fuge.
Renewable development
Tauhara came online in May 2024 following accelerated remediation works, providing new
renewable generation as gas supply tightened. Final commissioning activity is underway to
lift initial operating capacity to 152MW. Commissioning is also underway on Contact’s 51MW
Te Huka 3 geothermal power station, which is expected to be ready to receive steam by the
end of this month. These power stations will add 1.9TWh per annum of baseload renewable
output when full capacity is reached.
Construction has started on a 100MW grid-scale battery located at Glenbrook. Contact has
also committed to its first solar project through its joint venture with Lightsource bp – a
168MWp solar farm at Kōwhai Park, adjacent to Christchurch International Airport. Both are
expected online in 2026
iv
.
“Contact is demonstrating its commitment to invest in new renewable technologies by
executing on the best projects within its ~7TWh development pipeline, contributing to
security of supply as New Zealand decarbonises,” says Mr Fuge.
Contact is targeting a final investment decision in Q4 2024
iv
on Te Mihi Stage 2 – a ~100MW
binary plant which will be the first phase of the Wairakei A&B geothermal station
replacement. The investment decision will be considered alongside the plans to extend
~37MW of plant capacity at Wairakei A&B to 2031.
Decarbonising the portfolio
Emissions from electricity generation increased by 421tC0
2
e in FY24, with higher thermal
generation reflecting the delay in Tauhara commissioning and the drier hydrological
conditions. Emissions intensity from thermal generation was down 32% on FY23 driven
largely by the closure of Te Rapa on 30 June 2023. Contact is committed to being net zero
from its generation activities by 2035.

Contact Energy Ltd
3
Retail
Retail electricity net price has improved to partially recover rising energy and pass-through
costs. Total connections were up 37,000 on FY23, driven primarily by broadband and the
introduction of Contact Mobile.
Contact remains focused on supporting our customers in energy hardship, collaborating with
industry through ERANZ, which offers support programmes like EnergyMate, and partnering
with national social services agency Women’s Refuge and community group Good
Shepherd. Helping customers in energy hardship, Contact provided two million dollars of
support this year.
Outlook
Looking ahead, Mr Fuge said the next twelve months will see Contact operating more than
200MW of newly constructed geothermal power stations and building a diverse set of new
renewable projects as the company delivers on its Contact26 strategy to be a leader in the
decarbonisation of New Zealand.

1/ MORE INFORMATION
Investor enquiries Media enquiries
Shelley Hollingsworth Louise Wright
Investor Relations and Strategy Manager Head of Communications and Reputation
+64 27 227 2429 +64 21 840 313
shelley.hollingsworth@contactenergy.co.nz media@contactenergy.co.nz

2/ CONFERENCE CALL
A conference call to support the interim results announcement will be held at 11am, NZ (New
Zealand) time on 19 August 2024.
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
The onerous contract provision for AGS is assessed every 6 months in line with NZ IAS 37. In FY24 there has been a net movement in the
provision resulting in positive impacts of $12m EBITDAF and $5m profit. Underlying performance excludes these impacts. All variances and
commentary reflect movements in underlying performance.

ii

Refer to slide 50 of the FY24 results presentation for a definition and reconciliation between statutory profit and the non-GAAP profit measure
earnings before net interest expense, tax, depreciation, amortisation, change in fair value of financial instruments (EBITDAF). Contact now
reports impairments and write-offs outside of EBITDAF to better reflect underlying performance.

iii
Refer to Note A3 of the 2024 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.

---

1
1
2024 full year results
presentation
19 August 2024
Twelve months ended 30 June 2024

2
Disclaimer and important information
This presentation contains summary information and statements about Contact and its
businesses and activities as at the date of this presentation. The information is not held
out as being complete or exhaustive, nor does it contain all the information which a
prospective investor may require in evaluating a possible investment in Contact.
While all reasonable care has been taken in compiling this presentation, neither Contact
nor any of its directors, employees, shareholders nor any other person gives any
representation as to the accuracy or completeness of this information or accepts any
liability for any errors or omissions.
Contact recommends that you read this presentation in conjunction with its market
announcements and the materials attached to those announcements, and in particular
the market announcements and materials it released on the date of this presentation.
These are available on the NZX website (at www.nzx.com), the ASX website (at
www.asx.com.au) and on Contact's website (at www.contact.co.nz).
This presentation may contain certain forward-looking statements with respect to a
variety of matters. All such forward-looking statements involve known and unknown risks,
significant uncertainties, assumptions, contingencies, and other factors, many of which
are outside the control of Contact, which may cause the actual results or performance of
Contact to be materially different from any future results or performance expressed or
implied by such forward-looking statements. Such forward-looking statements speak only
as of the date of this presentation. Except as required by law or regulation (including the
NZX Listing Rules and the ASX Listing Rules), Contact undertakes no obligation to
update these forward-looking statements for events or circumstances that occur
subsequent to the date of this presentation or to update or keep current any of the
information contained herein. Any estimates or projections as to events that may occur in
the future (including projections of revenue, expense, net income and performance) are
based upon the best judgement of Contact from the information available as of the date
of this presentation.
EBITDAF, free cash flow, 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
FY24 highlights / Mike Fuge, CEO
Market update / Mike Fuge, CEO
Financial results and outlook / Dorian Devers, CFO
2
3
1
Agenda
33
Progress on strategy / Mike Fuge, CEO
3
4
Supporting materials
33
3
5
4 - 8
9 - 14
15 - 29
30 - 37
39 - 55

4
1
In FY23 Contact recognised a net onerous contract provision expense for AGS of
($113m) within EBITDAF and ($84m) within profit. In FY24 a net movement in the
onerous contract provision equated to $12m within EBITDAF and $5m within
profit. Underlying performance excludes these impacts. All variances and
commentary reflect movements in underlying performance.
Summary of key financial performance measures
Performance supports renewable investment
Focus on delivering geothermal developments and flexing to manage fuel constraints
•Initial high hydro storage was quickly drawn down; long
dry periods were punctuated by short, concentrated
inflow periods; gas supply tightened; and intermittent
generation increased. The market observed:
‒Higher wholesale prices. Record prices observed in
December / January and June 2024.
‒Higher thermal generation compared to FY23.
Particularly evident in the second quarter (these
warmer months are usually highly renewable) as
water was conserved for winter 2024.
•High contracted sales volumes in anticipation of
Tauhara online and strong starting fuel position.
•Balanced thermal and acquired generation to meet
sales position. Contracted with market participants
to best utilise constrained gas through early winter.
•Hydro outage planning flexed around prevailing
conditions to capture opportune inflows.
•First calls on NZAS demand response made.
•Channel pricing aligned closer to wholesale market.
Market
FY24
•Significant lines cost increases from 1 April 2025.
•Disappointing results from drilling campaigns across
all major gas field producers factoring into future gas
availability.
•Pricing volatility increasing, particularly in peak
periods, as intermittent generation continues to come
online, thermal plant is closed and gas production
slows.
•Decline in domestic gas production leading to a sharp
rise in the price of risk management products.
•Conditions continue to support Contact’s view of long-
term wholesale prices at $115-125/MWh (2024 real).
7
Medium term
•Expect to close Taranaki Combined Cycle (TCC)
gas-fired plant at end of 2024.
•New geothermal plant at Tauhara came online in
Q2 2024. Te Huka 3 expected online in Q4 2024.
Once at full capacity these will add 1.9TWh p.a. of
renewable output to the portfolio.
•Construction underway on 100MW Glenbrook
battery, adding renewable flexibility, and 168MWp
Kōwhai Park solar.
•Value of gas storage changes throughout the
transition.
2
Refer to slide 50 for a definition and reconciliation of EBITDAF. Contact now
reports impairments and write-offs outside of EBITDAF to better reflect
underlying performance.
3
Refer to slide 24 for a reconciliation of operating free cash flow.
4
Four-year average. See slide 24 for the basis of calculation of return on
invested capital.
5
Relates to interim and final FY24 dividends declared.
6
Includes capitalised interest.
7
As indicated in November 2022, updated for inflation and
includes update to reflect higher cost of capital. This is a
through-the-cycle measure in a balanced market. Prices
actually achieved are a function of the market at a point in
time.
Twelve months ended
30 June 2024 (FY24)
Twelve months ended 30
June 2023 (FY23)
Underlying
1
ReportedAgainst underlying
EBITDAF
2
$663m$675m↑16% from $573m
Profit$230m$235m↑9% from $211m
Profit per share29.1 c29.9c↑8% from 26.9c
Operating free cash
flow
3
$470m↑67% from $282m
Operating free cash flow
per share
3
59.8 c↑66% from 36.0c
Average ROIC
4
3.7%
↑
From 3.3%
Dividend declared
5
$292m↑7% from $273m
Dividend declared per
share
5
37.0 c↑6% from 35.0 c
Stay-in-business (SIB)
capital expenditure
(cash)
$110m↓3% from $113m
Growth capital
expenditure (cash)
6
$470m↓0% from $472m

5
Execution: What we delivered over the last 12 months
FY24 operational plan
Grow renewable
development
Decarbonise
our portfolio
Create
outstanding
customer
experiences
Strategic theme
Grow
Demand
Comparison to our FY24 operational plan
FY24 achieved
▪Conclude NZAS extension negotiations
with improved long-term pricing.
▪FID for one Green Chemical deal.
▪Facilitate at least 25MW of new demand.
▪Achieve FID for Kōwhai Park solar.
▪On track FID for North Island solar.
▪On track FID for wind.
▪Final Investment Decision on BESS (battery).
▪Tauhara operational Q4 2023.
▪Net zero roadmaps agreed (Scope 1 and 2).
▪Investment plans for further carbon offsets.
▪Final Investment Decision on BESS (battery).
▪Sustained entry into the DJSI.
▪Greater than 615k connections.
▪Maintain leading cost to serve position.
▪Significantly grow non-energy gross margin.
▪Expansion of “It’s good to be home” brand position.
▪Pilot launch of Contact Mobile.
▪Electricity net price up by around 5%.
Complete /
on-track
Minor delay and / or
cost increase
Major delay and / or
cost increase
Key:
Concluded new long-term NZAS deal with improved pricing and demand response.
Around 30MW new demand facilitated.
Support for HWR Richardson hydrogen/diesel initiative. CO
2
commercialisation
opportunity validated. Advancing to Final Investment Decision in FY25.
Tauhara came online Q2 2024 after steam separation plant re-design and rebuild.
Final commissioning activity underway.
Achieved Final Investment Decision on 100MW BESS (battery) at Glenbrook.
Achieved Final Investment Decision on 0.3TWh solar farm at Kōwhai Park.
Consenting process underway for Glorit and Stratford solar options (each 0.3TWh).
Consent lodged on 0.9-1.2TWh Southland Wind project.
GeoFuture project adjusted to a phased replacement programme (Te Mihi Stage 2&3).
Te Mihi Stage 2 (around 100MW) proceeding to Final Investment Decision in Q4 2024.
Progressing to meet all carbon reduction commitments under Net Zero roadmap (scope 1 & 2).
Approved BESS (battery) investment to reduce reliance on thermal peakers.
C0
2
reinjection being installed on Te Huka 3.
Electricity net price up by >5% aligning closer to market while maintaining low churn.
Telco gross margin growth of >60%.
More than 620k connections, up ~6%.
Cost to serve per connection increase below CPI.
Net Zero generation brand campaign launched.
Contact Mobile launched with ~8k customers.
Commissioning underway on Te Huka 3. Expected online in Q4 2024.
Top rated New Zealand company in DJSI Asia-Pacific.
▪Achieve FID for GeoFuture.
▪Build Te Huka 3.

6
Delivering 225MW new geothermal generation
Supporting the decarbonisation of NZ by bringing two world class geothermal power stations online in 2024
Te Huka 3
Tauhara
▪Tauhara came online in May 2024 providing
new renewable generation ahead of winter as
the gas market tightened.
▪Power station ran continuously during 30-day
reliability run at ~152MW and was
successfully tested at ~174MW.
▪Current operation of Tauhara is providing an
important source of renewable baseload
generation, at low marginal cost, as fuel
constraints (hydro and gas) have deepened.
▪Final commissioning activity underway to lift
initial operating capacity to ~152MW.
▪Minor modifications will be made during the
first outage in October 2025 to uplift
operating capacity to ~174MW.
Key stats:
▪Recent project milestones include:
▪Completion of the NCG reinjection
system to capture and reinject carbon
released from geothermal fluid.
▪Steam field is ready to supply steam to
the power plant.
▪Power plant is ready to receive steam by
end of August 2024.
▪Power station remains on track to be online
in Q4 CY2024.
▪This will take the total new geothermal plant
completed and commissioned by Contact in
2024 to over 200MW, delivering 1.9TWh
1
p.a.
of renewable output when at full capacity.
Key stats:
1
Annual output is calculated based on 174MW / 51MW for Tauhara and Te Huka 3 respectively at 95% capacity factor across 365 days (24-hour operation).
2
PPAs totalling 25MW to Oji Fibre and Pan Pac expected to commence on completion of final commissioning activity; PPA of 62.5MW to Genesis commences 1 January 2025.
3
Total project cost under board approvals. Tauhara includes performance payment to the EPC contractor as a result of bringing the plant online earlier than scheduled.
4
In FY25 Contact expects to recognise Tauhara assets of around $1,080m which includes capitalisation of interest and is after adjusting for the write-off recognised in FY24 relating to remediation work.
Capacity (planned)
Annual output (at full capacity)
1
Status
Capacity under PPA
2
Total project cost
3,4
174MW
~1,450GWh
On line
87.5MW
$924m
Capacity (planned)
Annual output (full year)
Expected online
Total project cost
3
51MW
~430GWh
1
Q4 CY2024
$300m
StatusCommissioning

7
Glenbrook battery investment to enhance
Contact’s renewable energy flexibility
Battery investment key metrics
Battery capacity
100MW
Modular format
56 Tesla
megapacks
Total project cost
Up to
$163m
2
Target schedule
Online by
Q1 CY2026
1
Based on a range of revenue sources including ancillary services (instantaneous reserves and frequency keeping), price arbitrage and fuel cost savings.
2
Includes sunk cost of $5.4m.
Initial EBITDAF
~$15-20m p.a.
(average)
1
%
Target IRR
9% to 10%
Operating costs
~$5m p.a.
Participation across
physical, reserve and
frequency-keeping markets
North Island location, close to
retail load, reducing North/
South Island price separation
Reduces reliance on gas
peakers by offering
intra-day peaking
Expansion option with
Tesla to increase capacity
to 130 MW / 260 MWh
Supports new wind and
solar on an intra-day
and intra-week basis
✓✓✓✓✓
Sources of value
Supports retail shape and
can support price cap and
virtual battery products for
tier 2 retailers

✓
Storage duration /
discharge
2 hr /
~200MWh
Battery investment metrics are compelling, supported by a range of strategic benefits
Note: Battery will be located on a three hectare site leased from NZ Steel, adjacent to Transpower’s GXP at Glenbrook. Consent granted by Auckand Council to operate for 35 years.

8
Investment in Kōwhai Park solar diversifies
Contact’s renewable generation base
Key investment metrics
(Contact)
Capacity
~168MWp
~150MWac
Generation under
PPA to Contact
80%
~210GWh p.a.
Project
costs
2
~$273m
$1.8m/MWac
Target
schedule
Online in
Q2 CY2026
%
Contact target IRR
1
Over 12%
Opex and
SIB capex
~$20/MWh
Technological and
regional diversification
of Contact’s
generation base
Delivers on the
combined strengths
within Contact’s JV
with Lightsource bp
Speed to market (target
online by winter 2026)
capturing opportunity in
wholesale markets
JV structure (50/50) and
77% project finance
3

reduces Contact’s required
total capital outlay
✓✓✓✓✓
Strategic benefits
One of New Zealand’s
largest solar farms with
300,000 panels and a 35
year expected useful life

✓
Annual
output
~275GWh p.a.
Speed to market expected to enhance returns available to Contact from this attractive investment
1
Includes JV returns and acquired generation. Return on acquired generation will ultimately depend on sales channel and market conditions.
2
Excludes financing costs of $43m. Includes development costs.
3
Bank facilities executed with remaining lender conditions precedent being completed in coming weeks. The final numbers could deviate slightly from those presented here once outstanding activities are completed.
Comprehensive solar
EPC contract with
CHINTEC (with network
connection by Ventia)
(Remainder sold merchant within JV)
Key investment metrics
(Project)
Contact
PPA term
15 years

Contact
PPA price
<$90/MWh
(With CPI escalation)

9
Market update

10
National electricity demand
Source: EMI, Contact.
Does not include NZAS
National electricity demand (TWh)
Regional
change (%)
FY24 vs FY23
Source: EMI, Contact
Market demand
New Zealand electricity demand was up ~2% on FY23
Total national electricity demand increased
by 0.95 TWh (2% from FY23).
•A 15% increase in demand year on
year in Huntly was largely driven by
increased demand at the Te Kowhai
node. This will be partly driven by the
shift from embedded to grid-sourced
generation at Te Rapa.
•Dry conditions in South Canterbury
increased demand at major irrigation
nodes, accounting for the majority of
the 15% demand increase.
•East Coast regional demand was down
9%, with Pan Pac's Whirinaki site
closed in 2023 after Cyclone Gabrielle
flooding impacts. The plant returned
online gradually through 2H24.
Drivers of underlying demand growth
include data centres, South Island process
heat and residential.
(2%)
15%
1%
15%
8%
2%
1%
5%
5%
5%
3%
2%
5%
1%
0%
1%
6%
4%
(9%)
5.0
5.2
5.1
4.9
5.0
5.0
5.0
10.1
10.110.3
10.6
10.2
10.5
11.2
26.1
26.1
25.8
26.1
25.8
25.6
25.9
FY18FY19FY20FY21FY22FY23FY24
41.3
41.4
41.2
41.6
41.1
41.1
42.1
+2%
+2%
North IslandSouth Island (ex NZAS)NZAS

11
Hydro generation was down ~11%
on FY23 (wet year), with materially
lower hydro inflows offset by a
~1.7TWh storage usage.
Impacts included:
•
Higher spot and futures
wholesale prices.
•
Increased reliance on thermal
generation and higher industry
carbon emissions.
New renewable generation online:
•
Geothermal uplift reflects lower
outages, Tauhara initial
generation and Wairakei uplift
(geothermal remains >2x wind).
•
Wind uplift reflects Harapaki and
Kaiwera Downs coming online.
•
First grid-scale solar
(~0.001TWh).
Generation by type (TWh)
The electricity market consumed ~1.7TWh of hydro storage in FY24, supplementing hydro generation volumes
towards mean. Together with reduced coal stockpiles and stored gas (AGS), the electricity market consumed
~3.6TWh of stored energy in FY24.
Source: EMI (generation data) & MBIE (emissions data)
Source: NZX Hydro data
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
Jul-
22
Dec-
22
Jul-
23
Dec-
23
Jun-
24
Mean
Actual
1H231H24
Storage
TWh
National hydro storage

Carbon emissions (mT)
1
Carbon emissions for FY24 Apr-Jun quarter has been estimated using historic conversion rates with actual generation data.
Low hydro inflows impacted generation mix
Fuel supply
Below mean hydro inflows and higher demand saw increased thermal generation
2H242H23
FY24 saw a 1.7mT (74%) increase in carbon
emissions on higher thermal generation.
3.7
3.1
2.9
2.1
2.5
7.3
7.1
3.5
24.0
27.0
7.6
23.9
4.9
3.1
2.4
3.9
1.2
FY22
0.5
FY23FY24
Gas
Coal
Hydro
Geothermal
Wind
Solar
Other nonidentified
generation
43.243.1
44.1
4.0
1

3.8
2.3

12
Demand
Carbon
Short-term external factors that
can influence the market
Changes as at 30 June 2024
in comparison to 30 June 2023
Short-term
wholesale
electricity
prices
>$1bn drilling /
maintenance on major
domestic fields over the
past 2-3 years have
been unsuccessful at
changing the overall
trend of output decline
5
.
Spot gas prices up
~310%
6.
Methanol pricing at
US$341/t
(up 22% YoY) but
constrained gas affecting
production levels
2
Demand was up ~2%
year on year
3
Thermal coal prices
lower
2
(US$133/t, down
~11% YoY)
Forward wholesale pricing is reflecting low hydro
storage and gas decline (fuel availability risk)
Hydro storage has been
volatile over the last 12
months. Controlled
storage swung between
~130% of mean (~800
GWh above mean) in
July 23 to ~66% of mean
(~910 GWh below
mean) in June 24
1
.
Wholesale and futures electricity pricing ($/MWh)
Wholesale market
0
20
40
60
80
100
120
140
160
180
200
220
240
260
280
300
320
Jun-
15
Jun-
16
Jun-
17
Jun-
18
Jun-
19
Jun-
20
Jun-
21
Jun-
22
Jun-
23
Jun-
24
10 year
average
spot price =
$114 /MWh
Long-dated futures (>12 months)
Short-dated futures (<12 months)
Monthly average spot price
Source: EMI wholesale pricing
Carbon prices have remained subdued (~$51 / NZ unit)
4

with the most recent June ETS auction attracting no bids
1
NZX hydro information;
2
Bloomberg;
3
EMI;
4
Carbon match;
5
Recent drilling in the Kupe field (well KS-9) was unsuccessful at increasing production. In addition, both Pohokura and Maui fields have seen lower than average gas
production during CY24 ~10TJ/day. Enerlytica June 2024.;
6
Energy Market Services

Weak hydrology conditions over the past 6 months, renewable intermittency, and increasing scarcity and cost of gas, have exacerbated spot price volatility and pushed both the spot
and near-term futures prices up significantly. Long-dated futures have also priced higher over the year in response to market expectations of fuel price and availability.
However, these long-dated prices are less volatile as they also reflect longer-run factors such as demand / supply and the return requirements of new-build renewables.

13
•Competition remains intense despite sustained high wholesale futures
prices. Market churn continues to reflect this with switching continuing
at ~19%.
•Tier 1 retailers’ market share over the last two years has remained static at
84% (84% June-22 & June-24), albeit Genesis has added the most
connections (+10%), with Contact, Mercury and Meridian relatively stable.
•Tier 2 retailer growth rates have been varied, with total market share flat over
the last two years (at 16%). Some retailers have grown strongly (Flick,
2degrees) while others have been declining (Electric Kiwi, Pulse) possibly
due to choices to reduce retail channel exposure / leverage existing hedges.
•Contact’s electricity connections were up +6k from June 2022 to June 2024
equating to 20% market share.
Change in retail customer electricity connections (000s)
30 June 2022 – 30 June 2024
2yr % change2yr ICP delta (1000s)
Retail electricity tariff changes (c/ kWh)
Tier 2: +10k connections
•Increasing wholesale energy and, more recently, network costs have
resulted in a lift in Residential electricity tariffs, with a compound annual
growth rate of 3% across the last five years.
•Average tariff increases for the year to March 2024 of 5% were largely in
line with consumer price inflation (~4%)
1
. Households have been largely
insulated from increasinginput costs due to retailers’ longer-term view of
pricing that rides through short-term volatility.
•As the energy industry decarbonises, cost pressure for retailers is expected
to remain, including:
‒Significant investment in lines and distribution infrastructure.
3
‒Continued elevated wholesale futures prices.
•This will result in an increase in the cost that consumers will pay over the
coming years.

12 months
ended:
Tier 1: +55k connections
Source: EMI
Source: MBIE
16.8
18.2
18.6
19.5
20.7
12.3
11.1
11.6
12.0
12.4
Mar-20Mar-21Mar-22Mar-23Mar-24
29.1
29.4
30.2
31.5
33.1
+3%
Differences in retail strategies apparent
Retail electricity market
Reflects range of views on the value of retail as a channel; Pass-through costs increasing
Lines (c/kWh)Energy & Other (c/kWh)
2
1
Stats NZ CIP index increase in the 12 months to March 2024.
2
Compound annual growth rate.
10%
1%
1%
0%
-11%
-5%
79%
22%
105%
0
20
40
60
80
100
120
-80
GenesisMercury/
TrustPower
Meridian
-66%
ManawaNovaPulseFlick
-17%
Electric
Kiwi
2Degrees/
Vocus
OtherContact
3
The Commerce Commission indicated that the transmission and distribution component of a household’s electricity bill will
increase on average, by $15 per month from 1 April 2025, for affected networks.

1414
Topical Regulatory matters: Net Zero 2050
imperative for NZ remains
•Declining performance of NZ’s natural gas fields with
recent drilling campaigns underperforming expectations.
•Indigenous capacity and flexibility limited.
•MBIE undertaking Fuel Security Study.
•Reversal of oil and gas exploration ban may increase
longer-term supply, short-term supply remains tight.
Fuel security
Contact’s focus on accelerating new renewable generation, flexible storage and customer-focused demand response solutions aligns
with the political and societal imperative for the market to deliver a secure, low emissions, and renewable electricity market.
Lines assets
regulation /
investment
Resource
management reform
•BCG report noted 30% increase in spend required on
distribution infrastructure in 2026-30 relative to 2021-25.
•Draft decision on 2025-30 revenue caps (effective 1 April
2025), would see the lines component of an average
household’s electricity bill increase by $15 per month for
affected networks in the first year, with further increases
expected over the following four years
1
.
•Increase largely reflects CPI and changes to WACC, but
it will have a material impact on some communities.
•Wide ranging resource management reforms underway,
including Fast Track Approvals Bill, amendments to the
Resource Management Act (RMA), and work to
strengthen the NPS-REG.
•Will play a crucial role to meet infrastructure challenges
of decarbonising NZ economy.
ThemeContact Approach
Timing
•Contact transitioning from gas reliance +
investing in renewable flex e.g. batteries.
•Closure of Taranaki Combined Cycle gas
plant (expected to close December 2024)
reduces Contact’s reliance on gas.
•Ahuroa Gas Storage facility provides Contact
with some control over fuel availability for
thermal assets over the short-medium term.
•Balance required: Crucial investment /
Consumer impact.
•Recommends reducing connection costs,
aiding electrification projects.
•Stepping up our hardship support – no
disconnection or reconnection fees for non-
payment.
•Contact seeks to utilise the proposed fast-
track consenting Bill (if enacted) to enhance
flexibility in the Clutha scheme.
•Community engagement remains central to
Contact’s approach.
•Engaging with officials and Ministers on wider
reforms for alignment with our decarbonisation
strategy.
•Bill to repeal oil and gas ban will be
introduced in second half of 2024.
•Fuel security study to start later
in 2024.
•Final decision on lines revenue caps
due in November 2024.
•New charges come into effect on
1 April 2025.
•Select Committee due to report back
on Fast Track Approvals Bill in
September. We expect Bill to pass by
the end of 2024.
•Second RMA Amendment Bill to be
introduced later in 2024.
•Work on NPS-Reg ongoing.
1
Draft revenue limits and quality standards for electricity lines companies for 2025-2030, Commerce Commission New Zealand, May 2024.

15
Financial results
and outlook

16
Key themes from the financial results
Uplift in expected and normalised
EBITDAF; Outperformed FY24
guidance; Expecting $770m in FY25
1
Non-cash accounting topics:
Net movement in the AGS onerous contract provision
of $12m within EBITDAF; Write-offs $50m outside
EBITDAF (peaker, Tauhara, software upgrades)

Cash conversion elevated by high
thermal generation and
capitalisation of Tauhara interest
Accelerated domestic gas decline
leading to more expensive risk
management products
Shift in national fuel mix leading
to more pronounced
summer / winter pricing
1
Normalised and expected.
Higher near-term pricing is a
feature of the energy transition,
enabling investment in
innovative technologies

17
113
63
61
460
--11
5
19
--23
--24
-12
675
573
663
+90
127
235
84
90
26-31
3
-50
-19
-5
211
230
+19
Profit ($m)
Excluding the onerous contract provision, EBITDAF up $90m (underlying) largely reflecting the better
alignment of long-term channel prices to wholesale market prices
Profit of $230m for FY24
EBITDAF ($m)
Increase in
thermal
efficiency due
to closure of
Te Rapa and
high proportion
of TCC
generation
Wholesale
prices saw
higher realised
C&I, CFD and
merchant sales
Renewables
down 88 GWh
due to a decrease
in hydro
generation
partially offset by
Tauhara
1
Fixed costs
higher due to
inflation impacts,
growth and
transmission
7531
FY24 results
FY23 profit
Net
interest
costs

EBITDAF
Depreciation
& Amortisation
Tax

Change in
FV of
financial
instruments
(outside
EBITDAF)
FY23 EBITDAF1. Renewables5. Gas, carbon and
acquired
generation price
7. Fixed
costs
FY24 EBITDAF2. Net
volume
Retail pricing
aligning to
higher energy
and pass-
through costs
2
Down largely
due to the gain
on sale from
Te Rapa in
FY23 and Te
Rapa steam
revenue
6
3. Market
channel
pricing
2
FY24 profit
Onerous contract provision before tax
Reported EBITDAF
Onerous contract provision after tax
Reported profit
4. Long-term
channel
pricing
6. Other
income
Sales volume
increase
~19% YoY,
but needed to
be backed
with thermal
fuel
4
1
Impact calculated at thermal SRMC.
2
Market channel pricing includes reduced $/MWh location losses.
Movements in profit and EBITDAF are shown on an underlying basis i.e. exclusive of the impacts of the onerous contract provision for AGS. Impacts of the onerous contract in FY23 are as follows, EBITDAF (-$113m), interest (-$3m), tax +$32m, NOPAT
(-$84m). Impacts of the onerous contract in FY24 are as follows, EBITDAF +$12m, interest (-$5m), tax (-$2m), NOPAT +$5m.
Asset
impairment
/ write-offs

18
Wholesale EBITDAF
1
(underlying, $m)
Retail EBITDAF ($m)
Corporate / unallocated costs ($m)
Business performance by segment
EBITDAF (underlying) up by $90m
Refer to slides 19 - 21
Refer to slide 22
632
746
186
235
66
FY23Generation
costs
(including
acquired
generation)
Total
contracted
revenue
Trading,
merchant
revenue
and losses
FY24
+114
-14
-32
FY23
1
Electricity
Volumes
62
87
Electricity
Prices
10
Other
products
2
5
OpexFY24
-18
Electricity gross margin
(-$24m)
Electricity
and network
cost inflation
Price recovery
2
Other products includes retail gas and telco gross margins.
FY24 results: Segmental performance
-44
-51
FY23
2
Inflation
(4 - 5%)
3
4
Strategy FY24

1
Simply and Western included within Wholesale EBITDAF.
Underlying EBITDAF is shown excluding a net ($113) million onerous contract provision
expense for AGS in FY23 and a net movement in the onerous contract provision of $12m
in FY24.
3
Stats NZ CPI increase over the 12 months to June 2024
plus wage inflation.

19
Electricity generated or acquired (GWh)
Costs up on increased thermal and acquired generation volumes
FY23FY24
Electricity generated or acquired costs ($m)
Generation costs
FY24 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
•
Hydro generation of 3,628GWh was down 291GWh (7.4%) on FY23
and below mean (3,900GWh) following a reasonably dry end to
1H24 (a very dry hydro sequence in the final quarter).
•
Geothermal volumes were up 203GWh on FY23 (6.4%). This
increase on last year was a result of Tauhara coming online in the
final quarter and a higher consented mass take from the Wairakei
field.
•
Variable rainfall sequences, largely concentrated in three distinct
periods, resulted in significant swings in hydro generation over FY24.
This meant long periods of dry conditions, particularly in 2H FY24,
and significantly higher thermal generation than the prior year.
Thermal generation of 1,620GWh was up 213% (1,103GWh) on
FY23. ​
•
Acquired generation was significantly higher than FY23 up 290% to
cover a delayed Tauhara completion date.
Costs
•
Renewable generation costs were up $17m (16%) on FY23 due to
higher geothermal generation and a marginally higher average
carbon price. Also greater allocation of indirect costs as portfolio mix
changes.
•
Thermal generation costs, were up $95m (77%) on significantly
increased thermal volumes and increased gas pricing as a result of
tightening supply (FY23: $7.9/GJ FY24: $8.5/GJ). However, thermal
efficiency increased on FY23 as a result of greater use of TCC due
to peaker outages and the sale of Te Rapa in FY23 (FY23:
11.8TJ/MWh, FY24: 8.1TJ/MWh).
3,185
3,388
3,919
3,628
517
1,620
585
150
FY23FY24
Acquired
Thermal
Hydro
Geothermal
7,772
9,220
105
114
109
32
126
34
123
50
218
113
18
26
93
62
26
27
18
93
7
Generation type Cost
type
5
Generation
type
Cost
type
257257
443443
+186
93%
Renewable % of
own generation
81%
$33.03/MWh
$48.02/MWh
1
Gas storage costs exclude the ($113m) onerous contract provision expense for AGS in FY23
and the net movement in the AGS provision of $12m in FY24.
Development
Acquired generation
costs

20
482
562
151
163
190
376
76
67
35
12
-11
FY23

11
3
-11
FY24
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
936
1,171
+235
3,787GWh
$148.3/MWh
Contracted
revenue ($m)
Diversified mix of long-term and ASX linked sales channels
2,573GWh
$146.3/MWh
+60GWh
+$18.8/MWh
+1,136GWh
+$14.3/MWh
•The closure of Te Rapa in June 2023 saw a significant decline in steam sales in FY24. the
remaining steam sales ($3.4m) reflect sales from geothermal operations.
•Strategic fixed price sales were 196GWh lower than FY23, reflecting marginally lower
volume under the NZAS support contract and the expiration of a long-term supply contract
with Fonterra. Prices of strategic fixed priced sales were up marginally on the prior period
($1.3/MWh). In FY25 Contact expects strategic fixed price sales pricing to increase
materially reflecting the recent long-term agreement with NZAS.
•With elevated starting hydro storage and in anticipation of Tauhara coming online, Contact
increased its FY24 contracted load. This took the form of short-dated CFD sales and some
additional C&I sales which would be backed by gas if required. CFD sales in FY24 were up
1,136GWh on FY23 and priced $14.3/MWh higher on average, reflecting elevated
wholesale spot and short-dated futures prices.
•In response to the delay in the Tauhara online date, and to manage its fuel position, Contact
acquired generation (see slide 19) which effectively backed out much of these additional
CFD and C&I sales.
•In 2H FY24 significant calls were made under the Swaption provided to Meridian, backed by
TCC. Contact was able to undertake tolling arrangements with other market participants at
mutually beneficial times in the year.
•Fixed price variable volume electricity sales to the Retail segment were 60 GWh higher than
FY23 (+$79m). Prices were up $18.8/MWh to $148.3/MWh, reflecting higher wholesale
prices over the three preceding years.
Wholesale contracted revenue
24
1,129GWh
$143.9.0/MWh
+30GWh
+$6.7/MWh
FY24 results: Wholesale business
1,219GWh
$55.2/MWh
-196GWh
+$1.3/MWh
Year-on-year
changes to
volume and price
FY24 volumes
and price

21
Trading EBITDAF ($m)Long / short position (GWh)
$178.4/MWh
4.8%
($8.5 / MWh)
9.0%
($7.4 / MWh)
•FY23 was characterised with abundant
hydrology, with low wholesale prices.
Contact reduced generation from more
expensive fuel sources leading to less
merchant generation over the year.
•FY24 conditions included:
‒Elevated wholesale spot prices.
‒Delay to Tauhara online and lower
hydro.
‒Calls made on the swaption to
Meridian, increasing sales.
‒This limited merchant generation to
513GWh (6%).
•LWAP / GWAP improved to 4.8% as dry
conditions over 2H FY24 reduced South
Island generation, improving South Island
prices relative to North Island prices.
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
$82.1MWh
Spot purchases and sell
CFD settlement
Spot sales and buy CFD
settlement
Merchant generation
91
-56
-73
8
FY23FY24
-48
18
513
93
7,600
-7,600
FY23
8,707
-8,707
FY24
93
513
FY24 results: Wholesale business
LWAP/
GWAP
losses

22
1
Retail business performance
EBITDAF ($m)
Managing through rising wholesale input costs while growing market share through a multi-product strategy
Revenue & Tariff
1
($m)
FY23FY24Variance
$m$mTariff¹$mTariff
Electricity revenue
9371,0182878117
Gas revenue
90964065
Telco revenue
668272162
Other income
9101
Total revenue
1,1021,206104
Contract Asset (closing)
43(1)
# of connections (closing)
2
584k621k
Cost to serve/connection
3

$120$123
1
Tariff is $/MWh for electricity, $/GJ for gas and $ per month per customer connection for Telco.
2
Retail connections only, excludes Simply Energy.
3
Reflects total operating costs (direct and indirect) / average connections.
6
10
32
8
9
17
9
7
-69
-74
FY23FY24
-14
-32
Gross Margin (GM) is Revenue less Cost of Goods
(Networks, meters, levies, energy, carbon and telco)
4
Input costs shown per MWh at the GXP.
FY24 results: Retail business
Other
Gas GM
Electricity GM
Telco GM
Other operating
expenses
Retail margins have contracted, driven by sustained high wholesale
prices and rising distribution costs.
•Retail EBITDAF decreased by $18m on FY23 largely driven by the
$87m increase in electricity input costs that were not fully passed
through to customers.
The average retail electricity tariff increased by 6.5% reflecting
targeted retail price rises to partially offset rising wholesale and lines
cost increases.
•Around 91% of customers received a price increase in the last 12
months.
As the energy industry decarbonises, cost pressure for retailers is
expected to remain, including:
•Significant investment in lines and distribution infrastructure.
5
•Continued elevated wholesale futures prices.
This will result in an increase in the cost that consumers will pay over
the coming years.
Connections grew strongly in 2H24 particularly through telco and Time
of Use (ToU) electricity Good plans, with a focus on multi-product
customers.
•Total connections +37k on FY23with telco up 23k and energy
up 14k.
•Multi-product customers up 12% on FY23, driven by strong telco
product attachment (including successful launch of new mobile
product option) alongside ToU Good plans growth.
Cost to serve – increased by $3/connection, largely driven by mobile
product launch marketing spend, wage inflation and higher bad debt.
This was partially offset by productivity improvements through
continued growth in digitised interactions.
70k
86k
428k
FY23
73k
109k
439k
FY24
Gas
Telco
Electricity
584k
621k
Closing connections (k)
5
The Commerce Commission indicated that the transmission and distribution
component of a household’s electricity bill will increase on average, by $15
per month from 1 April 2025, for affected networks.
Electricity
transfer price
4
$129/MWh$148/MWh
Networks,
meters and
levies
4
$113/MWh$118/MWh

23
Other operating
cost movement
($m)
Base
movement
Non-recurring
•FY23 one-off impacts represent strategic execution set up costs, Contact’s
share of BCG industry report, cost of retaining Te Rapa employees until plant
closure and cyclone recovery costs incurred atWhirinaki and Geothermal
sites. This has been offset by FY24 costs relating to tail of cyclone recovery
costs and one-time spend linked to the evaluation of our Contact26 strategy.
Base movement
•General inflation of 4-5% impacting operating costs, including labour cost,
rates and insurance inflation.
•Headwinds include increased level of customer bad debts and increased
hosting and licence costs associated with our software platforms.
•Increased expenditure is offset by productivity improvement in our Retail
Business and reduction of costs associated with Te Rapa due to its closure.
Growth and sustainability
•$1m incremental investment related to retail connection growth.
•$2m investment in advertising associated with launching Contact Mobile.
•$1m increases associated with Tauhara opex, specifically in relation to rates.
•$4m operating costs to deliver on strategic growth priorities including;
•Sustainability and furthering ESG outcomes;
•Procurement; and
•Increase in corporate functions to support growth activity.
•$1m costs associated with additional uptake of Contact’s updated paid
parental policy “Grow your Whanau” and Women’s Refuge sponsorship.
Operating costs rise due to inflationary
adjustments and non-recurring expenses
Base savings
General cost inflation
Invest in
growth and
sustainability
FY24 results: Operating costs
Headwinds
FY23 One-off Impacts
FY24 One-off Impacts
3
5
8
5
4
11
FY23Non-recurringBase movementGrowth &
Sustainability
FY24
233
2
10
253
Non-recurring

24
•Higher underlying EBITDAF as outlined on slide 17.
•Delta in working capital changes of $86m between FY24 vs FY23. This relates to usage of gas
inventory with higher thermal generation and higher net carbon liability. This is relative to FY23
where gas inventory and carbon balances increased on lower thermal generation.
•Tax paid is down $8m on lower July wash up payments vs FY23.
•Stay-in-business capital expenditure (cash) remains relatively consistent with a decrease of $3m.
In year spend includes additional spend on emergency repairs at Wairakei and spare Peaker
engine damaged in FY24.
12 months
ended
30 June 2024
12 months
ended
30 June 2023
Comparison
against FY23
EBITDAF (underlying)$663m$573m↑$90m
Working capital changes$31m($55m)↑$86m
Tax paid($97m)($105m)↑$8m
Interest paid, net of interest capitalised($21m)($25m)↑$4m
SIB capital expenditure($110m)($113m)↑$3m
Non-cash items included in EBITDAF$4m$7m↓($3m)
Operating free cash flow$470m$282m↑$188m
Operating free cash flow per share59.8 c36.0 c↑23.8 c
Cash conversion (OpFCF / EBITDAF)71%49%↑22%
Return on invested capital (ROIC)
Cash conversion for FY24 up following strong EBITDAF, positive working capital changes and lower tax paid
Cash flow and capital expenditure
Sources and uses of cash ($m)
FY24 results: Cash flow
16414620017496
NOPAT - $m
1
NOPAT is calculated as annual EBIT less tax (tax includes annual tax expense and movements in deferred tax over the year).
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 $50m) + non-current assets (adjusted to remove non-
current derivatives).
2
ROIC average is calculated as NOPAT (4-year average) / Average IC (4-year average).
3
Annual NOPAT (FY) / Average IC (FY)
354
275
89
2
470
1
27
Sources
6
470
10
Uses
852852
Cash Movement
Debt drawdown
OpFCF
DRP
Sale of asset
Strategic investments / acquisitions
Growth investment
Dividends paid
Realised losses on market derivatives
0
1
2
3
4
2.4%
3.6%
3.7%
3.7%
3.3%
3.7%
ROIC (average)
2
ROIC (FY)
3
4,836
4,575
4,482
4,518
4,874
5,349
FY19FY20FY21FY22FY23FY24
251
Net operating profit after taxes (NOPAT) / Invested capital (IC)
1
Average IC
($m)

25
Growth capital expenditure
FY24 results: Growth capital expenditure
Step-up in growth capital expenditure in FY24 reflects the advancing nature of Contact’s renewable
development projects
•The Tauhara geothermal station has been generating since May 2024. Final
commissioning activity is underway and further modification work is planned for the
first statutory outage in October 2025. Tauhara remained within Capital Work In
Progress as at 30 June 2024 as final EPC testing was incomplete.
•Construction of Te Huka 3 is near complete and commissioning is underway. Plant is
expected online in Q4 2024. The remaining growth capex is expected to fall in FY25.
•Remaining spend on Te Mihi Stage 2&3 (previously GeoFuture) and wind projects
reflects current pre-FID approval levels and will be updated after final investment
decisions, as applicable.
•Investment in a 100MW grid-scale battery (BESS) at Glenbrook was confirmed in
May 2024. The project is expected to be completed in FY26 with growth capex falling
across both FY25 and FY26.
•For major growth projects Contact capitalises interest from the time of final
investment decision (FID) or significant pre-FID works through to commissioning, on
a rate that reflects the average portfolio interest rate.
•Investment in Kōwhai Park solar was confirmed in August 2024. Contact’s investment
will not be captured within growth capex, rather it will be recognised within investment
in joint ventures and associates.
Growth capital expenditure – cash basis ($m)
1
Up to
30 June 2023
12 months ended
30 June 2024
Remaining under
current
approvals
Total
2
Tauhara$714m$138m$72m$924m
Te Huka 3$110m$136m$54m$300m
Te Mihi Stage 2&3$12m$98m$34m$144m
Wind$5m$8m$2m$15m
Glenbrook battery$0m$5m$158m$163m
Capitalised
interest
$99m$74m$18m
3
$191m
Total$940m$459m$338m$1,737m
1
Excludes $11m associated with Western Energy coil tube drilling and deployment of demand flex technology.
2
Total under current Board approvals. Tauhara includes performance payment to the EPC contractor as a result of bringing the plant online earlier than scheduled.
3
Relates to Te Huka 3 geothermal development (FY25 only) and Glenbrook battery development (life of project).

26
•A Green Australian Medium Term Note (AMTN) was
issued during the year. This was partly to refinance a
maturing tranche of USPP in December 2023, but also
provided additional funding for the ongoing capital
investment programme.
•During the year Contact’s hydropower assets gained
green certification from the Climate Bonds Initiative
(CBI).
‒To gain this certification, international experts
were brought on-site to undertake a Hydropower
Sustainability Assessment and assess Contact’s
ESG performance, benchmarking the hydro
schemes against best international practice.
‒This certification has increased Contacts green
borrowing programme by $1.7bn.
‒Contact received silver certification from the
International Hydropower Association.
•Contact’s planning aligns with maintaining its investment
grade credit rating. This requires net debt to EBITDAF to
remain below 3.0x over a sustained period. Point
estimate net debt to EBITDAF is currently 2.7x and
Contact’s EBITDAF outlook, DRP and capacity for
additional hybrid bonds provide the ability to manage
this metric effectively.
Contact’s sustainable finance principles are built on diversified sources of funding
Closing net debt ($m)
Face value of borrowings less cash
Interest rate (%)
Weighted average gross interest
2
on average borrowings
Net debt to EBITDAF (x)
Includes S&P adjustments (prior to FY20, AGS was treated as a lease)
3
Borrowing maturities ($m)
Average tenor of 5.9 years as at 30 June 2024
Strong balance sheet
1
Includes $87m of collateral held on deposit for margin calls associated with the trading of electricity price derivatives on the ASX.
2
Gross interest includes all interest on borrowings, bank commitment fees and deferred financing costs. Unwind of leases, provisions and capitalised interest not included.
3
Illustrated here on a point basis based on expected S&P adjustments. FY21 and FY22 have been restated based on latest understanding of S&P approach. See breakdown on slide 54.
990
1,036
774
1,025
1,474
1,834
-229
25
-47
FY19
22
-44
FY20
21
-150
FY21
25
-168
FY22
49
-140
FY23
47
FY24
1
968
1,014
645
882
1,383
1,652
Lease obligationsBorrowingsCash on hand
67
434
225
100
135
350
300
150
250
350
7
FY25
7
FY26
7
FY27
22
4
FY28FY29FY30FY31FY52
107
292
357
625
367
Undrawn bank facilities
Domestic bonds
USPP
NEXI
Capital bonds
AMTN
2.3
2.4
1.4
1.8
2.6
2.7
FY19FY20FY21FY22FY23FY24
1,224
1,029
974
892
1,310
1,727
5.3%
FY19
5.2%
FY20
5.2%
FY21
5.4%
FY22
5.8%
FY23
6.1%
FY24
Average gross interestAverage gross debt
FY24 results: Key balance sheet metrics

27
Dividend for FY24 of 37 cents per share
•Final dividend of 23 cents per share is imputed up to 91% or 21 cents per share for qualifying shareholders. This
represents a pay-out of 62% of FY24 operating free cash flow per share and 92% of the average operating free cash
flow over the preceding 4 financial years (FY20-FY23).
•The dividend policy is to pay-out between 80-100% of average operating free cash flow of the preceding four years.
•Record date of 28 August 2024; payment date of 27 September 2024.
•The NZD / AUD exchange rate used for the payment of Australian dollar dividends will be set on 5 September 2024.
Dividend per share for FY24 is up 6%
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 FY24 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 29 August 2024 to confirm participation in the plan.
•Trading period for setting price for the DRP is 27 August 2024 to 2 September 2024. DRP strike price will be
announced: 3 September 2024.
Ordinary dividends ($m)
Declared
Final dividend
Interim dividend
% pay-out of annual operating free cash flow
3939
35
35
37
73%
83%
97%62%
Operating free cash flow
Average operating free cash flow for the preceding four financial years
Dividend policy range: 80-100% of average operating free cash flow
for the preceding four years
325
260
FY20
309
247
FY21
326
261
FY22
333
266
83%
FY23
318
256
92%
FY24
363
291
85%
FY25
290371
330
➢Annual operating
free cash flow
100%
80%
Dividend level
as a % of preceeding
4yr operating fcf
165
163163
164
182
115
109109
109
110
FY20FY21FY22FY23FY24
280
272272
273
292
cps
97%
282470
1
This calculation is based on the expected ordinary dividend of 39 cps.
2
All dividend decisions are a matter for the Board at the conclusion of each reporting period. These align to the dividend policy and are dependent on business and market conditions when each payment decision is made.
Dividend expectations
•Contact has indicated that it expects to lift the FY25 interim dividend by 2cps to 16cps, with total expected dividends
in FY25 of 39cps (up 11% on FY23). While it undertakes the Te Mihi Stage 2 development (the first stage of Wairakei
geothermal station replacement capex) additional increases to dividend per share are not currently anticipated.
2
•On this basis, dividends in FY25-FY27 are expected to be imputed up to ~65%.
•Reliable ordinary dividends are expected to increase over time with growth in operating free cash flow.
Reflects 92% of the average operating free cash flow for the preceding four years
1

28
Uplift in Contact’s expected FY25 EBITDAF to be driven
by the realisation of growth investment
164
44
600
FY24 EBITDAF
(normalised
and expected)
Renewable
generation
changes
Long-term
channel price
19
Market
channel price
-32
Gas, carbon
and risk
management
costs
-19
Net volume
impact
-5
Other
operating costs
and income
770
FY25 EBITDAF
(normalised
and expected)
+170
¹ See slide 40 for assumptions underpinning FY24 normalised and expected earnings.
Normalised and expected EBITDAF ($ million)
1
FY25 normalised and expected EBITDAF includes generation from Tauhara and Te Huka 3 which together
represent $1.2bn of investment in renewable generation
480
520
550
600
553
546
573
663
FY21FY22FY23FY24
Actual result delivered
Guidance (at beginning of the year)
Guidance vs Actual
Like-for-like increase of $170m (28%) on year-on-year guidance
Strong track record of delivering
performance above guidance
(Guidance reflects normalised and expected EBITDAF
based on mean hydrology conditions)
Normalised and expected EBITDAF is based on mean hydrology conditions
Start to FY25 has been characterised by low hydro inflows and high wholesale prices. These conditions have a partially offsetting
impact on earnings (resulting in above or below normalised expected performance).
Of note, July 2024 EBITDAF was $9m below normalised and mean expected.

29
Guiding principles
Invest to deliver value accretive growth
•Returns improved through prioritisation of non-equity funding.
•Projects ranked considering returns available and overall portfolio implications.
Optimise existing operations and manage risk
•Reduce carbon exposure.
•Manage market volatility during the thermal transition.
•Disciplined approach to sustaining capital spend.
•Strong operating cash flow.
Our commitments
Continue to attract capital
•Deliver competitive shareholder returns including dividend commitment.
•Balance sheet strength.
Efficient deployment of stay-
in-business Capex
Higher SIB capex over next three years reflects
higher risk associated with the wholesale
market environment and includes (FY25-FY27):
➢BAU SIB capex $75m-$85m p.a.
1

➢Accelerated SIB capex programme $48m.
2
➢Wairakei extension ~$25-35m (indicative).
3
1
Reliable ordinary dividends
that increase in line with
growth in cash flow
Pay-out ratio of 80-100% of average
operating free cash-flow over the preceding
4 years.
➢92% in FY24 (37cps dividend declared).
2
Allocate capital to strategic
priorities, with an ability to scale
down in downside scenarios
Total growth cash capex of
$1.4-$1.5bn over FY23-25.
4
3
Investment grade credit metrics
through the cycle
Target BBB <3x net debt to EBITDAF.
If temporarily above, always have
clear plan to restore metrics.
4
What this means
Recap: Capital allocation framework
GeothermalWindSolarBatteryHydro
Target returns9-11%8-10%10-12%8-9%8-9%
Returns on
projects at or
nearing FID
>10%tbc>12%9-10%tbc
Considering supportive post-NZAS market conditions,
current market risks around fuel availability and a broad range
of attractive projects, we will prioritise investments to
grow shareholder value and distributions
1
Includes ~$10m p.a. of provisions. Excludes geothermal well drilling which may be required within the period.
2
Reflects planned spend in the next 3 years relating to the $150m accelerated SIB capex programme announced to the market in 2021.
3

Current indicative range of SIB capex to be incurred in FY26-27 for Wairakei extension activity. To be confirmed at FID for Te Mihi Stage 2.
4
Excludes project spend that has not yet proceeded to final investment decision.

30
Progress on
Strategy

31
Our strategy to lead NZ’s decarbonisation
Enablers
Transformative ways of working:
create a flexible and high-performing
environment for New Zealand’s top talent
Outcomes
Growth
Pivot our business to a new growth era that
captures the value unlocked by decarbonisation
Resilience
Deliver sustainable shareholder returns,
aligned with our ESG commitment
Performance
Realise a step-change in performance, materially
growing EBITDAF through strategic investments
Strategic
theme
Objective
Grow
demand
Attract new industrial demand with
globally competitive renewables
Grow renewable
development
Build renewable generation and
flexibility on the back of new demand
Decarbonise
our portfolio
Lead an orderly transition
to renewables
Create outstanding
customer experiences
Create NZ's leading energy and services
brand to meet more of our customers’ needs
Operational excellence:
continuously improving our operations
through innovation and digitisation
ESG: create long-term value through our strong
performance across a broad set of environmental,
social and governance factors

32
Contact is preparing for further investment
in renewable generation and storage
Geothermal generation potential (TWh p.a.)
1
Includes mean geothermal generation (existing stations) plus Tauhara volume based on 135MW currently online. Also includes ~50GWh uplift already delivered on Wairakei field (see note 6).
2
Represents uplift in Tauhara output expected from completion of final commissioning activity in 2024 (0.1TWh) and the first planned outage in October 2025 (0.2TWh)
3
For projects included in the “land access secured” category, indicative output is shown based on early estimates of capacity per hectare and assumed capacity factors of ~40% for wind and 20-25% for solar.
4
Consent already received for 100MW grid-scale battery at Stratford.
5
All uncommitted investments are subject to Board investment decisions. The Tauhara, Te Huka 3, Roxburgh, Kōwhai Park and Glenbrook battery investments have been committed to.
6
In FY24 Contact operationalised the higher consented fluid take at the Wairakei field (5kt per day) translating to a ~50GWh p.a. uplift in average geothermal generation (before new developments online) applying a ~30MWh/kt efficiency factor.
7
45GWh p.a. uplift is based on mean hydrology conditions.
Wind and solar options under development (TWh p.a.)
3
Land access secured
Consenting underway
Under construction
4TWh
Wind
2TWh
Solar
Key updates (including grid-scale batteries)
•Kōwhai Park solar (0.3TWh) and Glenbrook battery
(100MW) now under construction.
•Stratford battery (100MW) consented.
•Consenting underway includes:
‒Glorit solar (0.3TWh).
‒Stratford solar (0.3TWh).
‒Southland Wind (0.9-1.2TWh).
•Earliest expected FID for these projects is FY26.
•Contact is investigating the potential to include
additional battery capacity within the Glorit and
Stratford solar consenting processes.
4
•Expected FID and online dates depend on
supportive market conditions and funding
arrangements.
20242025
2026
2027>2028
>2028
Calendar year
Tauhara
(1.1TWh)
Te Huka 3
(0.4TWh)
Te Mihi
Stage 2
(0.8TWh)
Roxburgh
(45GWh
7
uplift)
Tauhara 2
Te Mihi Stage 3
(up to 1TWh)
Remaining capacity
(consented) net of full
Wairakei closure
Wairakei
Partial
closure
(-0.8TWh)
Kōwhai Park
(Solar)
(0.3TWh)
Battery
(100MW)
Tauhara
(0.2TWh
uplift)
Planned Geothermal plus other renewables under construction
5
Expected generation (indicative):
Wairakei
(~50GWh
6
uplift)
Current
generation
(mean)
1
0.3
Tauhara uplift
2
0.4
Te Huka 3Current +
under
construction
0.3
Te Mihi 2&3
(uplift
remaining net
of Wairakei
retirement)
0.7
Tauhara
(remaining)
Potential
under current
consents
4.4
5.2
6.3
+1.8
Under constructionRemaining consented
(up to)
Tauhara
(0.1TWh
uplift)

33
Phased development plans for Wairakei geothermal
Ohaaki
Tauhara
Te Huka
Te Mihi
Stages 2&3
Wairakei
A/B/binary
Te Mihi
Poihipi
Current generating assets on the Wairakei steamfield
include Wairakei A/B/binary, Poihipi and Te Mihi
Wairakei geothermal resource
consented to 2058
Project
Scale
Technology
Plans for
Wairakei
A/B/binary
Development
approach
Single build
GeoFuture
Up to 200MW
Binary or Steam Turbine
Closure CY2026
Phased build
Te Mihi Stage 2
Around 100MW
Binary (2 units)
Full extension of Wairakei A/B/binary to mid CY2027
+
Extension of 30MW steam turbine + 7MW binary to mid CY2031
Te Mihi Stage 3
Around 100MW
Binary (2 units)
Project
Scale
Technology
Indicative plans
for Wairakei
A/B/binary
Development
approach
FromTo
New builds and extensions remain subject to Board final investment decisions
Not proceeding
Target online
2H CY2026Mid CY2027Mid CY2031
Target online
Te Mihi Stage 2 – Key metrics
Wairakei geothermal station extension – Indicative costs
Extension
works
(indicative)
Full extension of Wairakei
A/B/binary to mid CY2027
Extension of 30MW steam turbine
+ 7MW binary unit to mid CY2031
Indicative SIB capex
(FY26- FY27)
$25-35m
•Costs associated with the 1-year extension of the full Wairakei geothermal station reflect maintenance costs, those
associated with statutory recertification, and final steps to comply with June 2026 consent conditions (consented to
operate to mid CY2031).
•Working case assumes the extension of 1 steam turbine and 1 binary unit with identical standby units (steam and
binary) maintained on reserve shutdown. This allows for increased reliability with 24 hour return to service capability.
•Costs to be confirmed at the same time as Te Mihi Stage 2 FID (Q4 CY2024).
•Total cash cost of extensions (SIB capex, opex) FY26-FY31 of $30-35/MWh based on the Wairakei station indicative
output profile on slide 34.
Estimated forward
capital expenditure
1
1
Excludes capitalised interest and sunk costs. Contact is assessing the allocation between Te Mihi Stage 2 and 3 of the $114m sunk costs (approved prior to May 2024) and this will be confirmed at FID for Te Mihi Stage 2.
Estimated MW
(net export to grid)
Estimated plant
capacity factor
Production / injection
capacity secured
~$600-700m
~100MW
95%
100%
Contact remains committed to the long-term development of the Wairakei geothermal field
Schedule (final
investment decision)
Q4 CY2024
Estimated annual
output
~0.8TWh p.a.

34
Contact plans to deliver 0.4TWh p.a. total
uplift in Wairakei field output
Indicative output on the Wairakei field (Wairakei geothermal station, Te Mihi, Poihipi)
(Subject to revisions and will be confirmed at final investment decision on Te Mihi Stage 2)
0.3
0.3
0.3
0.30.3
0.8
0.8
0.8
0.8
0.8
1.4
1.4
1.3
1.4
1.4
0.3
0.3
0.3
0.3
0.8
1.0
1.1
1.1
1.0
0.8
1.4
1.3
1.4
1.4
0.3
0.3
0.3
0.3
1.3
1.0
1.5
2.0
2.5
3.0
3.5
0.5
FY19-23
average
FY24FY25FY26FY27FY28FY29FY30FY31FY32
2.7
2.8
2.7
2.7
2.5
2.8
2.7
2.8
2.8
3.1
0.1
+0.4
Wairakei geothermal station (existing)Te MihiPoihipi RoadTe Mihi Stage 2Te Mihi Stage 3
TWh
Does not account for potential outages
associated with Te Mihi Stage 3 tie-in work
Outages included to complete Wairakei station extension
works, to be confirmed with Te Mihi Stage 2 FID
Four-yearly statutory outage at Te Mihi will be utilised to
complete tie-in works for Te Mihi Stage 2 (~150 GWh impact)
Total field uplift of 0.4TWh p.a. is expected to be achieved in FY32 with Te Mihi Stage 3 online (compared to historic average).
Contact has already delivered ~50GWh of this benefit from its revised resource consent.
~50GWh uplift from
revised resource consent
1
1
In FY24 Contact operationalised the higher consented fluid take at the Wairakei field (5kt per day) translating to a ~50GWh p.a. uplift in average geothermal generation (before new developments online). This is based
on full utlisation of the additional consented fluid at an efficiency rate of ~30MWh/kt.

35
Impacts of the energy transition in New Zealand
are starting to become clearer
Theme
Characteristics
Observable impacts
Domestic natural gas
production in decline
Thermal power stations
closing as more intermittent
renewables come online
High level of activity to
advance renewable
electricity builds
•Ageing natural gas fields with limited
forward plans for further investment.
•Drilling / maintenance on major
domestic fields unsuccessful.
•Overall trend of output decline.
•Scarcity of new long-term gas
contracts (and at elevated prices).
•Spot gas trading at over $35/GJ.
•Higher reliance on coal for electricity
generation.
•Stored gas and coal depleted.
•More intermittent renewable
generation entering the market,
leading to increased price volatility.
•High-cost baseload gas generation
no longer aligns to market needs.
•Thermal power stations closing.
•High fixed costs associated with
running thermal plant need to be
recovered on lower volume.
•Wholesale electricity prices
materially higher when thermal
generation is required.
•High volume of proposed renewable
developments putting pressure on
consenting bodies.
•Constrained contracting market.
•Generators and independent
developers competing for quality
resource e.g. land / sites.
•Backlog in consenting processes.
•Cost escalation on domestic
construction and productive
resource.
•Expected returns on Contact’s
projects at or nearing FID remain
above targets.
1
1
See slide 29.

36
Market changes indicate a value shift to flexibility,
impacting future investment prioritisation
Contact’s view of expected long-run wholesale
electricity prices supports the firmed long-run
cost of new renewables (annual average $115 -
125/MWh)
1.
Observed construction costs for new
renewables have continued to rise.
113
123
142
223
SummerSummerWinterWinter
+10
+80
Historical spot price at OTA
CY2017 – CY2023 ($/MWh)
3
ASX Future prices at OTA
CY2027 ($/MWh)
4
Long-run wholesale
electricity prices
above historic
Winter Summer Price
Separation Widening
Value shift to
flexibility
LRMC of renewables
($MWh 2024 Real)
2

“ Flexibility in supply and demand becomes the
‘secret sauce’ ........as the system shifts towards
renewable supply.”
Market Development Advisory Group
While average prices reflect long-run
economics, ASX Futures illustrate winter
prices rising by substantially more than
summer prices.This reflects the requirement
to recover thermal system fuel costs and the
expected increase in must-run renewables
within the market.
We expect value to shift from intermittent
renewable generation to the owners of
flexible, renewable storage.
85100
105
90
Long run price
expectation
$120/MWh
Firming margin
Grid
scale
batteries
Demand
response
Biomass
Hydro
operating
ranges
Pumped
hydro
Sources
of new
renewable
flexibility
1
As indicated in November 2022, updated for inflation and includes update to reflect higher cost of capital. This is a through-the-cycle measure in a balanced market. Prices achieved are a function of the market at a point in time.
2
Based on announced capex and financing structures on the most recent projects for wind (Kaiwera Downs 2) and solar (Kōwhai Park) and discount rates tied to broker WACC estimates for the industry of 7-9%.
3
EMI daily simple average spot price data from 1/10/16 – 31/12/23. Winter is defined here as 1 Oct – 31 March, Summer is defined as 1 April – 30 Sept.
4
ASX futures prices as at 5 August 2024

37
Our operational plan
FY25
Achieve FID for CO
2
commercialisation.
Te Huka 3 online Q4 CY2024.
Glenbrook Battery (BESS) on-track for
online Q1 CY2026.
Kōwhai Park Solar on track for online for
Q2 CY2026.
Close TCC (Taranaki Combined Cycle) gas
generation plant. Expected to close
December 2024.
Multi-product customers >148k (up from 140k).
Cost to serve <$123/connection.
Grow renewable
development
Decarbonise
our portfolio
Create
outstanding
customer
experiences
Strategic theme
Grow
Demand
Achieve FID for Te Mihi Stage 2.
Lodge consent for Stratford Solar.
Achieve consent on Glorit Solar.
Achieve consent on Southland Wind.
New demand facilitated since FY21 to reach >120MW.
1
Add 15MW of contracted flexible demand.
2
Sustained New Zealand leadership
position in the Asia Pacific DJSI.
Targeting electricity net price up 2-3%.
Scale Hot Water Sorter programme
3

to >20k homes (up from ~5k).
What you can expect in the next 12 months
1
Cumulative measure (~105MW at 30 June 2024).
2
Up from 173MW contracted at 30 June 2024.
3
Residential Demand Flex.

38
Questions

39
Supporting
materials

40
Normalised and expected FY25 EBITDAF
Assumes mean hydrology conditions
Strategic fixed price1,900GWh$80/MWh$152m
CFDs1,770GWh$154/MWh$273m
C&I1,300GWh$150/MWh$195m
Retail3,800GWh$154/MWh$585m
Other income³$47m
$1,252m
Hydro mean3,900GWh$0/MWh-$0m
Geothermal average4,620GWh$4/MWh-$19m
Thermal350GWh$130/MWh⁴-$46m
Acquired350GWh$215/MWh-$75m
-$139m
Length⁵$86mTransmission/Storage-$71m
Location losses⁶-$85mOperating expenses-$272m
Total$1mTotal-$343m
1.All volumes are at the Grid Exit Point (GXP)
2.Net price is equal to tariff less pass-through costs (network, meters and levies) /MWh
ASSUMPTIONS FOR NORMALISED EARNINGS
3.Steam sales, retail gas gross margin, telco gross margin and other income
4.Gas price of $8.20/GJ, carbon price of $80/unit and thermal portfolio heat rate (10GJ/MWh)
5.Length of 450GWh p.a. assumed
6.Locational losses of 5.1% on spot purchases and settlement of CFDs sold at a
wholesale price of $190/MWh
* Fuel is natural gas and carbon costs.
** Retail volume contracted competitive risk remains on pricing achieved.
1,460
310
Channel choices maximise
long term value¹
1
Net price² driven by
best commercial practices
2
x
=
FY assumptions that deliver expected & normalised EBITDAF for FY25
Fuel cost
Net Revenue
Trading
Fixed costs
Hydrology & Asset
availability optimise generation
3
4
Total
x
=
Access to and price of fuel* drives
financials & risk position
Total
Trading delivers value to more
than offset locational losses
5
Digitalisation & continuous
improvement optimise fixed costs
6
x
x
x
x
x
x
x
=
=
=
=
=
=
=
1,070
230
3,800
1,900
CFDs
C&I
Retail
Strategic fixed
$154/
MWh
$150/
MWh
$154/
MWh**
ContractedUncontracted
1,252
-139
-343
1
770
x
Jul-24Sep-24Jan-25Mar-25Nov-24May-25Jul-25
320
311
311
299
240
222
211
190
204
184
158
135
218
178
218
181
218218
184184
245
203
245
203
245
203
244
200
ASX Futures $/MWh
monthly contracts
At 5 July 2024
$80/
MWh
OTA
BEN
Note, all figures are subject to rounding.

41
Guidance below EBITDAF
FY24 guidanceFY24 resultFY25 guidanceCommentary
Stay in Business Capex
$120-130m
1
$110m$115m - $125m
Stay in business accelerated programme
(cash)
$55m - $60m$39m~$40m
As at the end of FY24 we had spent $104m out of the $150m accelerated stay in
business capex programme.
Stay in business capital expenditure (cash)
BAU
$65m - $70m$71m$75m-$85m
Includes $10m of provisions related to consent obligations and decommissioning
activity.
Growth capital expenditure (cash)
2
$400m - $500m$470m$450m - $550mGrowth capital for Tauhara, Te Huka, GeoFuture, Wind and Battery projects.
Depreciation and amortisation
$250m - $260m$255m$275m - $285m
Reflects useful life changes on thermal and geothermal assets as well as
introduction of Tauhara and Te Huka unit 3.
Net interest (accounting)
$45m - $55m$40m$115m - $125m
Reduction in capitalisation of interest with Tauhara commissioning. Higher interest
rate environment and increased borrowings.
Cash interest (in operating cash flow)
$27m - $37m$21m$95m - $105m
Cash taxation
$95m – $105m$97m$110m - $120m
FY25 provisional payments based on FY23 results and higher final tax payment
relating to FY24.
Realised (gains) / losses on market derivates
not in a hedge relationship
$10m - $15m$3m$10m - $15mIncluding (gains) / losses on ASX market making.
Corporate costs
$52m$51m$52m
Inflation impacts in FY25 see corporate costs expected to be steady, noting that
FY24 included one-off impacts for consultant spend.
Target ordinary dividend per share
Minimum 35 cps37 cps39 cps
Payout in line with dividend policy and reflecting Tauhara and Te Huka 3 online
and new long-term NZAS deal reached in 2024.
1
FY24 guidance range is gross i.e. before the netting of insurance proceeds of $15m.
2
Growth capital expenditure includes capitalised interest.

42
Strategic fixed price1,150GWh$50/MWh $58m
CFDs2,500GWh$140/MWh$350m
C&I1,250GWh$145/MWh$181m
Retail3,700GWh$144/MWh$533m
Other income³$38m
$1,159m
Hydro3,900GWh$0/MWh-$0m
Geothermal3,250GWh$5/MWh-$16m
Thermal⁴1,800GWh$120/MWh-$216m
Acquired0GWh$0/MWh-$0m
-$232m
Length⁵$53mTransmission/Storage-$70m
Location losses⁶-$52mOperating expenses-$258m
Total$1mTotal-$328m
FY24 assumptions that deliver expected & normalised EBITDAF of $600m over a financial year
EBITDAF guidance reconciliation to actual FY24
Hydrology & Asset
availability optimise generation
3
4
Total
x
=
Access to and price of fuel* drives
financials & risk position
Increased market channel price
Normalised & Expected
Lower renewables
Other income
Actual FY24 (underlying)
Renewable generation below mean (-134GWh).
Impact calculated at expected thermal SRMC
Channel choices maximise
long term value¹
1
Net price² driven by
best commercial practices
2
Total
x
=
Trading delivers value to more
than offset locational losses
5
Digitalisation & continuous
improvement optimise fixed costs
6
x
x
x
x
x
x
x
=
=
=
=
=
=
=
1.All volumes are at the Grid Exit Point (GXP)
2.Net price is equal to tariff less pass-through
costs (network, meters and levies) /MWh
3.Steam sales, retail gas gross margin, telco gross margin and other income
4.Gas price of $9.50/GJ, carbon price of $70/unit and thermal portfolio heat rate (9.5GJ/MWh)
5.Length of 350GWh assumed
6.Locational losses of 4.3% on spot purchases and settlement
of CFDs sold at a wholesale price of $139/MWh
Fixed costs
Received $10m ‘loss and
constraint excess’ (LCE)
rebates
27
9
15
-16
12
3
13
600
663
Normalised and expected EBITDAF assumptions
FY24 results
With reconciliation to actual performance
x
Increased long–term channel price
Retail net price of $150/MWh higher than
full year expectation
Higher than expected CFD price partially
offset by higher $/MWh location losses
Gas, carbon, acquired generation price
Gas and carbon price as well as thermal
efficiency were favourable
Total sales volumes above expectations
Net volume impact
Risk management sales premiums and expected
losses from distressed gas sales not realised

43
43
48
57
76
53
852
1,069
1,023
939
1,269
-252
-258
-265
-291
-315
-46
-76
-85
-56
-74
-152
-230
-185
-94
-269
FY20FY21FY22FY23FY24
Electricity sales margin
Other gross margin
Fixed operating costs
Location losses
Variable fuel costs
446
553
546
573
663
Operating earnings (EBITDAF)
105
108
106
115
127
3.74
0.83
FY20
3.61
1.33
FY21
3.69
1.39
FY22
3.73
1.42
FY23
3.80
1.22
FY24
4.57
4.94
5.08
5.14
5.02
RetailLong-term sales
83
101
117
126
116
1.44
0.34
0.00
FY20
1.67
0.55
0.00
FY21
1.13
0.39
0.00
FY22
0.52
0.15
FY23
1.62
0.59
0.02
FY24
1.77
2.23
1.52
0.67
2.22
ThermalAcquiredDistributed generation
2
Electricity sales
Variable fuel costs
11111
3.75
3.33
FY20
3.70
3.11
FY21
3.94
3.28
FY22
3.92
3.19
FY23
3.63
3.39
FY24
7.08
6.81
7.22
7.10
7.02
HydroGeothermal
(i) Renewables
(ii) Thermal and acquired
87
131
133133
150
2.17
1.26
0.86
FY20
1.23
1.94
0.93
FY21
0.94
2.10
0.63
FY22
1.10
1.44
0.09
FY23
1.13
2.57
0.51
FY24
4.29
4.10
3.66
2.63
4.21
Commercial and IndustrialCFDsSpot sales
(i) Long-term channels
(ii) Market channels
Price
($/MWh)
Volume
(TWh)
Price
($/MWh)
Volume
(TWh)
Fuel cost
($/MWh)
Volume
(TWh)
Fuel cost
($/MWh)
Volume
(TWh)
Integrated portfolio performance
Continuing operations ($m)
1
EBITDAF
1
2
1
2
1
Refer to slide 50 for a definition and reconciliation of EBITDAF. All EBITDAF figures are underlying i.e. excluding the impacts of the ($113m) AGS onerous contract provision expense in FY23 and $12m net movement in the AGS provision in FY24.
Contact no longer reports impairments and write-downs within EBITDAF in order to better reflect underlying performance.
2
Distributed generation reflects electricity purchased from solar customers within the retail business.
96
118117121
137
8.858
9.040
8.739
7.772
9.232
Price ($/MWh)
Volume (TWh)

44
Greenhouse gas emissions
Carbon reporting
1
Contact’s swaption with Genesis Energy ended 31 December 2022 and was not called during FY23.
IndicatorUnitTarget
FY20
FY21FY22FY23FY24
Direct GHG emissions (Scope 1)tC02e
45% reduction of 2018
Scope 1 and 2
emissions by 2026
(Absolute emissions
reduction target)
920,403
1,044,744786,842526,621947,491
-Stationary combustiontC02e920,4031,044,537786,544526,282947,131
-Mobile combustiontC02e
270
178297307332
-Fugitive emissionstC02e42913228
Indirect GHG emissions (Scope 2)tC02e
1,258
1,303
1,3991,957975
Sub-total Scope 1 and 2tC02e647,443921,9351,046,047788,241528,579948,466
Indirect GHG emissions (Scope 3)tC02e259,118317,384555,035394,784273,673265,034
-Category 1 – Purchased goods and servicestC02e
30% reduction of 2018
Scope 3 GHG
emissions from use of
sold products by 2026.
39,39716,699
6,3716,1976,522
-Category 2 – Capital goodstC02e18,05241,72657,87688,26679,185
-Category 3 – Fuel and energy
1
tC02e91,857330,207149,7431,0505,130
-Category 4 - Upstream distribution and transportationtC02e
14
27444108254
-Category 5 – WastetC02e1231491084758
-Category 6 – Business traveltC02e7192635671,2741,601
-Category 7 – Employee commutingtC02e606306832965927
-Category 11 – Use of sold productstC02e166,310165,259178,554175,603170,929
-Category 13 – Downstream leased assetstC02e306399289164429
Total Scope 1, 2 and 3 emissionstC02e906,5611,239,3191,601,0821,183,025802,2521,213,500

45
Contact generation output sold to the national grid (GWh)
Generation and sales position
3,323
3,256
3,333
3,114
3,283
3,185
3,388
3,479
4,231
3,752
3,698
3,940
3,919
3,628
1,812
1,421
1,360
1,592
1,046
1,620
FY18FY19FY20FY21FY22
439
FY23FY24
Thermal
generation
Hydro
generation
Geothermal
generation
8,614
8,908
8,445
8,404
8,269
7,543
8,636
Operational data
Renewable % of
own generation
sold to grid
79%84%
84%
81%
81%
87%94%
Geothermal generation (GWh)
Te Huka
Ōhaaki
Poihipi
Wairakei
Te Mihi
FY24 geothermal generation was 203 GWh higher than FY23 as a result of the increased
consented mass take from the Wairakei steam field and Tauhara coming online in late FY24.
1,372
1,382
1,415
1,240
1,386
1,380
1,062
991
1,045
1,081
1,055
998
1,405
411
388
335
339
331
308
1,064
280
310
340
299
322
323
274
316
203
198
FY18
186
FY19
198
FY20
155
FY21
189
FY22
176
FY23
127
FY24
Tauhara
3,323
3,257
3,333
3,114
3,283
3,185
3,388
Hydro generation (GWh)
An uncharacteristic El Niño weather pattern resulted in FY24 hydro inflow volumes 31% lower than FY23 and
the lowest seen since FY18. Further, inflows during the period were highly concentrated leading to spill, however
this was significantly lower than spill seen in FY23.
3,544
103
4,786
69
4,068
113
-28
4,276
-59
3,905
-50
5,450
3,745
-975
-1,606
-37
FY18
-148
FY19FY20
-275
FY21
-78
FY22
75
FY23
-230
FY24
3,479
4,231
3,752
3,698
3,940
3,919
3,628
Inflows stored include uncontrolled storage lakes
Inflows
Inflows
stored
Spill
Thermal generation (GWh)
1,071
1,013
871
1,126
673
164
1,395
528
207
291
234
179
148
223
211
195
195
213
190
125
3
90
FY18
5
83
FY19
3
79
FY20
18
81
FY21
4
81
FY22
2
78
FY23
1
FY24
1,903
1,503
1,439
1,673
1,127
517
1,620
Te Rapa
Spot
Whirinaki
Te Rapa
Direct
Peakers
TCC
FY24 thermal generation volumes were 1,102GWh higher than FY23 due to dry conditions in summer
2023 and winter 2024, as well as the delay to Tauhara online.

46
Plant and fuel performance
Geothermal fuel extracted at Wairakei vs consented (mT)
Wairakei, Poihipi and Te Mihi conversion effectiveness
(MWh per kT extracted)
31.6
31.4
31.1
30.5
31.0
30.4
29.2
FY18FY19FY20FY21FY22FY23FY24
-4%
Geothermal fuel performance
Taranaki combined cycle (TCC)
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
FY2037788%26%871120104
FY2137789%34%1,126193217
FY2237784%20%673180121
FY2337785%5%16410718
FY2437782%42%1,395184257
Hydro
Geothermal
Stratford Peakers
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
FY2078492%54%3,75290338
FY2178484%54%3,698167617
FY2278483%57%3,940121478
FY2378484%57%3,91974290
FY2478490%53%3,628164594
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
FY2042595%89%3,33399330
FY2142589%84%3,114175546
FY2242597%91%3,284140458
FY23410
4
94%89%3,18680254
FY24586
4
94%89%3,388 177 601
Te Rapa (spot generation only)
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
FY2020280%16%29116147
FY2120290%13%23423054
FY2220253%10%17921238
FY2320277%8%14820731
FY2420250%12%22317539
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
FY204198%51%19510621
FY214193%58%21317437
FY224195%54%19014528
FY234192%30%1259412
FY24
2
------
Plant availability
3
3
Availability Factor calculation includes all station outages (Planned, Maintenance, Forced) but does not consider plant deratings.
4
Reduction in geothermal net capacity in FY23 was a result of decommissioning of wells on the Wairakei steamfield. Increase in FY24 relates to Tauhara.
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
FY2015898%0%32931
FY2115894%0%184107.5
FY2215895%0%45972
FY2315882%0%24911.2
FY2415897%0%16871.1
Whirinaki
1
Percent change relates to the movement in geothermal mass extracted (mT) at Wairakei YoY.
2
Te Rapa was decommissioned at the end of the FY23.
10
20
30
40
50
60
70
80
90
100
0
100%
90
FY18
99%
88
FY19
100%
90
98%
87
FY21
100%
89
FY22
98%
89
FY23
100%
91
FY24FY20
+3%
1
% of geothermal fluid extractedWairakei mass extracted

47
Hawea storage (GWh)
Gas storage (PJ)
Closing storage
Closing storage (current)
Fuel storage movements
Source: NZX Hydro data
256
98
175
165
260
116
252
191
138
248
300
230
324
189
324
265
242
236
-406
-223
-239
-230
-332
-187
-325
-294
-288
2H201H212H211H222H221H232H231H242H24
Inflows
Opening storage
Releases
98
175
165
260
116
252
192
139
86
5.0
6.1
5.0
5.8
7.8
4.7
2.4
3.4
2.8
2.2
0.8
1.7
2.4
0.5
2.7
1.7
0.9
1.3
-1.1
-1.9
-0.9
-3.5
-0.7-0.7
-1.5
-2.5
-4.3
2H201H212H21
-0.4
1H222H221H232H231H242H24
Gas Injected
Gas Extracted
Opening Storage
6.1
5.0
5.8
7.8
4.7
2.4
3.4
2.8
1.6
Operational data
0
Transferred to
long-term storage
(PJ)
0
0
0
0
4
4
4
4
Long-term storage
1
1

Updated from previous reporting to 4.3PJ vs ~4 PJ. This change has been made to improve reporting of currently available
gas storage, there has been no material change in AGS total available storage capacity.

48
Contracted gas volumes (PJ)
Uses of gas (PJ)
Gas storage monthly injections and extractions (PJ)
Contracted and stored gas
Gas injectedGas extracted
8.1
3.4
0.9
2.6
4.6
5.4
4.5
6.1
1.7
1.4
2.0
5.3
7.4
5.9
6.0
2.3
5.5
5.2
3.6
CY20
-0.2
CY21CY22CY23
0.2
CY24
1
CY25
2
16.9
14.6
15.5
15.2
14.5
0.12
-0.28
Jul-
23
0.03
-0.61
Aug-
23
0.25
-0.28
Sep-
23
0.28
-0.16
Oct-
23
0.14
-0.06
Nov-
23
0.11
-0.14
Dec-
23
0.35
-0.21
Jan-
24
0.34
-0.28
Feb-
24
0.08
-0.81
Mar-
24
0.37
-0.25
Apr-
24
0.07
-0.46
May-
24
0.08
-0.53
Jun-
24
9.4
9.3
9.8
6.6
9.8
6.3
8.8
6.4
1.1
-0.7
-2.0
3.1
-2.0
-1.0
0.6
1.3
-8.2
-6.7
-4.4
-6.5
-3.3
-2.7
-6.7
-6.4
-1.7
-1.4
-1.6
-1.3
-1.6
-1.1
-1.4
-1.1
-1.6
-1.9
-2.7
-1.4
-1.3
-0.2
-0.5
1H21
-0.6
2H211H222H221H232H231H242H24
Net extraction
(injection)
Generation
Customer sales
Wholesale sales
Purchases
Short-term gas
Genesis
Swap
Maui
Pohokura
Operational data
1
CY24 reflects actual volumes and forecasts for the second half of the year.
2
CY25 reflects forecast volumes.

49
Contractual fuel position sufficient to
support expected FY25 sales position
Fuel position
Portfolio requirements for thermal generation (TWh)
Gas supply and demand FY25 (PJ)
3.5PJ
2
Hydro variation >>
1
Dry year reflects hydro generation in FY12 and wet year reflects hydro generation in FY15.
2
Assumes mix of TCC and peaker generation (portfolio heat rate (10GJ/MWh)).
3
This incorporates the lower bound of the range notified by our suppliers as disclosed to the market on 7 April 2024. Of note, if drilling results and well performance are lower than expected we could see a further reduction to this forecast.
GeothermalExpected
FY25
generation
Hydro in
“extreme
dry” year
1
"Extreme
dry" to
"mean"
year swing
Mean
thermal
required
Maximum
thermal
required
"Mean" to
"wet" year
swing
1
Minimum
thermal
required
Gas forecast
under contract
3

3.5
7.1
2.5
3.8
Mean Year
demand
FY25
Position
Mean Thermal
Retail
6.0
10.9
9.2
1.4
0.4
0.1
-4.6
-0.4
-2.9
-1.0
-0.3
Options in a dry year:
•Access to stored water
in Hawea.
•Access to gas in
Ahuroa Gas Storage
facility (AGS).
•Purchase spot gas or
short-term gas
tranches /
arrangements
•Stop selling
uncontracted electricity
•Acquire generation
from ASX
.
Acquired
generation
Short term gas
purchases