Contact delivers solid FY23 performance

contactenergy.co.nz
NZX release: 14 August 2023: Contact Energy FY23 Result
Contact delivers solid FY23 performance while investing for
decarbonisation
Key financial metrics

Twelve months ended
30 June 2023
FY23
Twelve months ended
30 June 2022
FY22
Underlying
1
Reported Against underlying
EBITDAF
2
$573m $460m ↑ 5% from $546m
Profit $211m

$127m ↑ 16% from $182m
Profit per share 26.9 cps

16.3 cps ↑ 15% from 23.4 cps
Operating free cash flow
3
$282m ↓ 15% from $330m
Stay-in-business capital expenditure (cash) $113m ↑ 51% from $75m
Growth capital expenditure (cash) $472m ↑ 62% from $291m
Overview
New Zealand renewable energy company Contact Energy (‘Contact’) today released its
financial results for the year to 30 June 2023.

• Net profit of $127m after recognising an onerous contract provision expense of $84m
($113m EBITDAF impact) following a review of the estimated available capacity of the
Ahuroa Gas Storage facility (AGS). Excluding AGS, underlying net profit was $211m.

• Underling EBITDAF (excluding the AGS provision) increased by $27m to $573m with
higher realised electricity pricing and a gain on sale of the Te Rapa co-generation
plant, partially offset by high gas and carbon unit costs, lower electricity sales volumes
and higher fixed operating costs.

• Operating free cash flow decreased by $48m to $282m. Working capital continues to
be elevated, with more gas and carbon units in inventory.

Contact has made significant progress on delivering to its Contact26 strategy and remains
focused on leading New Zealand’s decarbonisation by connecting customers with its
renewable development pipeline.


1
Contact has recognised a net onerous contract provision expense for AGS of $113m within EBITDAF and $84m within profit. Underlying
performance excludes these impacts. All variances are shown on an underlying basis.
2
Refer to slide 43 of the 2023 full year 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
has made reclassifications to better align with IFRIC guidance on IFRS 9 resulting in realised gains/losses from market derivatives not in a hedge
relationship (includes market making activity) no longer being reported in operating income (EBITDAF). FY22 figures restated accordingly.
3
Refer to note A3 of the 2023 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.

contactenergy.co.nz
• New geothermal station of up to 180MW at Te Mihi, GeoFuture, proceeding to final
investment decision in early 2024. Investment of up to $114m approved. Pre-
construction drilling to begin from September 2023.

• Preparing for final investment decisions on Kōwhai Park 170MWp solar farm and
100MW North Island battery in FY24.

• Planning to apply for resource consent at Glorit on the Kaipara Coast, northwest of
Auckland by the end of 2023 for the second 160MWp solar farm through Contact’s
joint venture with Lightsource bp.

• Te Rapa power station closed on 30 June 2023 as planned. Contact’s generation on
track to be more than 95% renewable by FY27.

• Strong endorsement of Contact’s retail offering, reaching approximately 589,000
energy and broadband connections.

- Introduced wireless broadband and Dream Charge time-of-use plan, enabling
customers to charge their EVs at home at lower night rates, contributing to the
decarbonisation of New Zealand. Contact Mobile launches later this month.

- Supported mass market customers by keeping average electricity price increase
realised year-on-year in line with general inflation, despite elevated forward
wholesale prices over the last three years.
_________________________________________________________________________

Financial performance

In FY23 Contact recognised an onerous contract provision expense of $84m after tax
($113m EBITDAF impact) following a review of the estimated available storage capacity of
AGS. This is a non-cash accounting adjustment to recognise the difference between the
expected benefits from access to gas storage and the contracted schedule of payments over
the remaining 10 years of the contract.

Reported net profit of $127m was down $55m on the prior year, with lower operating
earnings (EBITDAF) reflecting the onerous contract provision, higher interest expense
reflecting the higher interest rate environment and unfavourable movements in the fair value
of financial instruments as higher losses were realised from unhedged financial instruments,
partially offset by lower depreciation and amortisation and lower tax on earnings. Excluding
the impact of the AGS provision, underlying net profit was $211m, up $29m from the prior
year.

Underlying EBITDAF, which excludes the impact of the AGS provision, increased by $27m
to $573m, up five percent on the prior year, with higher realised electricity pricing as our
sales channels align closer to the wholesale market, and higher other income which included
a $7m gain on sale of Te Rapa. This was partially offset by continued higher thermal
generation input costs, lower electricity sales volumes and higher fixed costs driven by
inflation and the preparation of the business for growth.

Operating free cash flow decreased from $330m to $282m, down 15 percent year-on-year
with higher underlying operating earnings offset by higher stay-in-business capital
expenditure, higher cash tax paid on strong earnings in prior periods and unfavourable
working capital movements. Working capital remained elevated as Contact held more gas
and carbon units in inventory on lower thermal generation than the prior year.

contactenergy.co.nz

The Board approved a final dividend of 21 cents per share (imputed by up to 18 cents per
share for qualifying shareholders) to be paid on 26 September 2023; taking the annual
dividend declared for FY23 to 35 cents per share, which is in line with the prior year.

“Contact delivered a solid financial performance despite soft short-term wholesale market
conditions,” said Mr Fuge.

“We saw the highest nationwide hydro inflows in post-market history, with North Island
rainfall the highest on record. This depressed spot market prices and saw greater price
separation between the North and South Islands. We responded by purchasing excess
renewable electricity from the wholesale spot market and reduced our thermal generation to
the lowest in Contact history.”

Renewable development

Contact’s geothermal development activity is moving at pace, with plans to replace the
1950s-built Wairākei A and B power stations with a new station of up to 180MW at Te Mihi –
the GeoFuture project. Development costs of up to $114m have been approved and Contact
is targeting a final investment decision in early 2024.

“It is an exciting time for Contact as we focus on advancing our steamfield design work for
GeoFuture and we will start pre-construction drilling in September. This comes as we are
reaching completion of our world-class geothermal development at Tauhara,” said Mr Fuge.

The Minister for the Environment has approved the Southland Wind Farm Project for fast-
track consenting. If approved, the 300MW facility would be Contact’s first wind farm and
New Zealand’s largest. Together with its partner, Roaring40s, Contact continues to engage
with local communities and mana whenua.

Subject to taking a final investment decision in FY24, Contact’s joint venture with
Lightsource bp will begin construction on a 170MWp solar farm at Christchurch Airport,
Kōwhai Park in 2024. The joint venture’s second proposed solar farm development is in
Glorit on the Kaipara Coast, northwest of Auckland. The proposed site has good access to
the transmission grid and is expected to generate 0.3TWh per year. The joint venture plans
to apply for consent for the Glorit site in the second half of 2023.

Demand

Industry interest in converting to renewable electricity was strong, Mr Fuge said.

“In May we announced a pioneering energy agreement with NZ Steel. We will provide
30MW of flexible off-peak renewable electricity for its proposed new $300m electric arc
furnace. This will enable NZ Steel to scale down production in peak demand times or supply
shortages, with the project representing a significant step towards meeting New Zealand’s
climate change goals.”

The trend continued with accelerating opportunities with several other industrial companies
exploring similar opportunities to decarbonise industrial heat processes and cut fossil fuel
use.
The New Zealand Aluminium Smelter (NZAS) has indicated it would like to continue
operations at Tiwai Point beyond December 2024. “We are encouraged as we continue to
work closely with NZAS to negotiate a new agreement. The smelter is valuable to our
country, and our economy, particularly as a significant exporter. It is also highly carbon

contactenergy.co.nz
efficient in its production of premium aluminium, and a major employer and contributor to the
Southland economy.”

Decarbonising our portfolio
In June 2023, as planned, Contact closed its 44 MW Te Rapa gas-fired co-generation power
station. And the company has confirmed it won’t extend the operating hours of its gas-fired
Taranaki Combined Cycle (TCC) plant. While it will support security of supply with remaining
operating hours, decommissioning is expected at the end of 2024.

The 1.9TWh of new renewable generation that Contact will be bringing online at Tauhara
and Te Huka is enabling Contact to take these steps. And, after a successful trial at Te
Huka, Contact has confirmed it is exploring the feasibility of CO
2
capture and reinjection or
reuse across existing and planned geothermal plants.

“This year we have taken key steps towards decarbonising our own portfolio and now have a
clear path to achieve net zero emissions from our generation operations by 2035. We are
committed to doing this in an orderly manner, ensuring security of supply and energy
affordability to New Zealanders,” said Mr Fuge.

In line with Contact’s decarbonisation strategy, the company will be taking a final investment
decision on a 100MW battery in FY24. Contact has a preferred site option at Glenbrook,
subject to consenting, and has resource consent to build at Stratford where Contact has
existing operations.

“Investment in renewable energy flexibility in the North Island, close to retail load, is key to
our strategy to lead New Zealand’s decarbonisation. With more intermittent renewables
being introduced, grid-scale batteries will play an important role by storing energy during
periods of low demand and discharging power into the grid during the peaks. This
investment will reduce our reliance on gas peaking plant and will enable us to participate
across physical, reserve and frequency-keeping markets,” said Mr Fuge.

Retail
Mr Fuge said Contact’s retail business has continued with targeted growth in FY23. “Multi-
product customers are up 10% on FY22 driven by growth in our broadband business and
supported by the introduction of fixed wireless broadband and expanded time-of-use offerings
with the new Dream Charge EV plan. We’ve also been preparing to introduce Contact mobile,
which will launch later this month.” Contact has been named as a finalist for Energy Retailer
of the Year for the second year running.

Outlook
Looking ahead, Mr Fuge said the coming year will see Contact reaching significant milestones
in the delivery of its strategy to lead the decarbonisation of New Zealand.

“We’re preparing for Tauhara to come online by the end of the year, which will be a pivotal
moment for the company. We’re well on track to bring Te Huka 3 online by the end of 2024
and we’ll be taking final investment decisions on GeoFuture, Kōwhai Park and a 100MW
battery all within this financial year. I’m exceptionally proud of the team’s dedication in laying
the groundwork to realise our strategy.”

“We are excited about the future. We have a clear strategy, strong balance sheet with
supportive shareholders and stand ready to execute on the opportunities in front of us to lead
the decarbonisation of the New Zealand economy over the next decade.”

contactenergy.co.nz


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


2/ CONFERENCE CALL

A conference call to support the full year results announcement will be held at 10am, NZ
(New Zealand) time on 14 August 2023.

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

---

1
2023 full year results
presentation
14 August 2023
Twelve months ended 30 June 2023

2
Disclaimer and important information
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.
This presentation may contain certain forward-looking statements with respect to a
variety of matters. All such forward-looking statements involve known and unknown risks,
significant uncertainties, assumptions, contingencies, and other factors, many of which
are outside the control of Contact, which may cause the actual results or performance of
Contact to be materially different from any future results or performance expressed or
implied by such forward-looking statements. Such forward-looking statements speak only
as of the date of this presentation. Except as required by law or regulation (including the
NZX Listing Rules and the ASX Listing Rules), Contact undertakes no obligation to
update these forward-looking statements for events or circumstances that occur
subsequent to the date of this presentation or to update or keep current any of the
information contained herein. Any estimates or projections as to events that may occur in
the future (including projections of revenue, expense, net income and performance) are
based upon the best judgement of Contact from the information available as of the date
of this presentation.
EBITDAF, free cash flow and operating free cash flow are financial measures that are
“non-GAAP (generally accepted accounting practice) financial information” under
Guidance Note 2017: ‘Disclosing non-GAAP financial information’ published by the New
Zealand Financial Markets Authority, “non-IFRS financial information” under ASIC
Regulatory Guide 230: ‘Disclosing non-IFRS financial information’ and “non-GAAP
financial measures” within the meaning of Regulation G under the U.S. Exchange Act of
1934.
Such financial information and financial measures (including EBITDAF, free cash flow
and operating free cash flow) do not have standardised meanings prescribed under New
Zealand equivalents to International Financial Reporting Standards (“NZ IFRS”),
Australian Accounting Standards (“AAS”) or International Financial Reporting Standards
(“IFRS”) and therefore, may not be comparable to similarly titled measures presented by
other entities, and should not be construed as an alternative to other financial measures
determined in accordance with NZ IFRS, AAS or IFRS accounting practice) measures.
Information regarding the usefulness, calculation and reconciliation of these measures is
provided in the supporting material.
This presentation does not constitute financial or investment advice. This presentation
does not constitute an offer to sell, or a solicitation of an offer to buy, Contact securities
and may not be relied on in connection with any purchase of a Contact security.
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
FY23 highlights and market update / Mike Fuge, CEO4 -12
Financial results and outlook / Dorian Devers, CFO 13-27
Progress on strategy / Mike Fuge, CEO 28 - 32
2
3
1
Agenda
33
Supporting materials 33 - 46
3
4

4
1
Contact has recognised a net onerous contract provision expense for AGS of $113m within EBITDAF and $84m within profit. Underlying performance excludes these impacts. All variances and commentary reflect movements in underlying performance.
2
Refer to slide 43 for a definition and reconciliation of EBITDAF.Contact has made reclassifications to better align with IFRIC guidance on IFRS 9 resulting in realisedgains/losses from market derivatives not in a hedge relationship (includes market
making activity) no longer being reported in operating income (EBITDAF). FY22 figures restated accordingly.
3
Refer to slide 22 for a reconciliation of operating free cash flow.
4
Includes capitalised interest.
Twelve months ended
30 June 2023 (FY23)
Twelve months ended 30
June 2022 (FY22)
Underlying
1
ReportedAgainst underlying
EBITDAF
2
$573m$460m↑5% from $546m
Profit$211m$127m↑16% from $182m
Profit per share26.9 c16.3 c↑15% from 23.4c
Operating free cash
flow
3
$282m ↓15% from $330m
Operating free cash flow
per share
3
36.0 c↓15% from 42.4c
Dividend declared$273m↑$272m
Dividend declared per
share
35.0 c→35.0 c
Stay-in-business (SIB)
capital expenditure
(cash)
$113m↑43% from $79m
Growth capital
expenditure (cash)
4
$472m↑62% from $291m
Operatingconditions in FY23 were characterised by
the highest nationwidehydro inflows in post-market
history, with North Island rainfall the highest on
record. This led to:
•Lower wholesale spot prices.
•Lower thermal generation.
•Higher price separation between North and South
Islands.
Over the medium term:
•Pricing volatility increasing, particularly in peak
periods, as intermittent generation comes online.
•Electricity futures prices have softened with recent
reductions in spot coal and carbon prices.
•Pricing is still influenced by lower expected gas
availability, notified reduction in gas storage
capacity, the end of ‘swaption’ contracts and high
expected marginal cost of thermal fuel and carbon.
•Rising thermal fixed costs will need to be
recovered over less generation as renewable
penetration increases.
•Conditions continue to support a view of long-term
wholesale prices at $100-110/MWh (2022 real).
Summary of key financial performance measures
Delivering a solid FY23 performance while
investing for decarbonisation
Contact has responded to the short-term
conditions by:
•Securing additional gas in Q2 FY23
enabling additional CFD sales for 2023.
•Running short to take advantage of soft
wholesale market conditions.
•Reducing thermal generation, to the lowest
on Contact record, saving on fuel costs.
Contact over the mediumterm:
•Channel pricing aligned closer to the
wholesale market.
•TeRapa closed in June 2023 and TCC will
run until the end of its operating hours
(expected end of 2024).
•Preparing sales book for the Q2 FY24
commissioning of Tauhara geothermal
plant, which will add 1.4TWh of new
renewable output to the portfolio annually.
•Recognising a net $113 million onerous
contract provision expense within EBITDAF
for AhuroaGas Storage facility (AGS).
1
FY23 market

5
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

6
Strategic theme
FY23 achievements / progress
Updated ambitions (FY27)
1
Grow
demand
Completed assessment of hydrogen
economics
NZAS negotiations underway
10-year renewable energy attribute
agreement with Microsoft. Growing data
centre pipeline
Lock in major industrial electrification. Entered
30MW off-peak supply arrangement with NZ
Steel
Commence boiler electrification
Flexible demand more than 80MW
•Facilitate 100MW of new demand
•Reach 100MW total Demand Flex and start pivoting to
Demand Response
•New green chemical channel established contributing
incremental EBITDAF
Grow
renewable
development
Build Tauhara. Online Q4 2024.
Te Huka 3 investment decision and entered
build phase
Wairākei geothermal replacement
consented. GeoFuture proceeding to
investment decision in FY24
Selected to deliver 150MW solar farm at
Kōwhai Park. Proceeding to investment
decision in FY24
Secure and consent wind sites. Entering consenting
for 0.9-1.2TWh Southland wind project in FY24
Complete battery feasibility. 100MW battery
investment proceeding to investment decision in
FY24
Roxburgh turbine replacement
•Grow to 10.3TWh p.a of total renewable assets
from geothermal new build, solar and wind
•100MW battery operational
Decarbonise
our portfolio
•Scope 1 and 2 GHG emissions run-rate of ~300ktCO2e,
working towards our 2035 net zero commitment
•Renewable flexibility strategy to reduce reliance on
thermal peaking
Create
outstanding
customer
experiences
Targeted growth in broadband and energy
connections. Now more than 588,000, an
increase of over 65,000 since FY21
Unlock further cost to serve improvements
and increases in Net Promoter Score
through digitisation programme
•Greater than 685k connections
•Cost to serve (CTS) at global benchmark of <$80/
connection
•Triple EBITDAF contribution from non-energy lines of
business
•Top quartile NZ Business for Sustainability survey
2
and
most Trusted Energy brand
3
TeRapa closed in June 2023
Confirmed TCC will run its remaining
operating hours or as market needs
dictate. Decommissioning expected at
end of 2024
SAP ERP finance and generation upgrade
complete. CRM options to be reviewed
Wireless broadband launched along with new
targeted EV plan. Pilot offering of mobile in
August 2023
On track to meet all carbon reduction
commitments
Thermal review complete. Contact to manage its
thermal peaking assets through the energy
transition, playing a key role in system security
Execution: What we delivered over the past 12 months
Complete /
on-track
Minor delay and / or
cost increase
Major delay and / or
cost increase
Key:
1
Set in May 2023.
2
As measured by Kantar Better Futures survey.
3
As measured by Contact’s independently surveyed brand tracker.

7
Geothermal investment programme update
Supportingthe decarbonisationof New Zealand by building world class geothermal power stations
Te Huka 3
Tauhara
GeoFuture
2
Size (TWhp.a)
Online date
Spend to date (to 30 Jun)
1
Committed spend
1
FID date
Total expected project cost
Project progress (at30 Jun)
1.4
0.4
1.4
3
Q4 2023
Q4 2024
2H 2026
Feb 2021
Aug 2022
Early 2024
96%
Pre-FID development
38%
$748m
$116m $12m
$880m
$300m$114m
4
$880m
$300m
$5.3 –5.7m/MW
3
Based on mid-point of 160-180MW indicative capacity range. Represents a net uplift of 0.4TWh per annum following the closure of Wairākei plants.
4
Approved pre-FID development costs. We are undertaking drilling from September 2023 and advancing steamfield design.
1
Includes sunk costs. Excludes capitalised interest.
2
Subject to final investment decision (FID).

8
National electricity demand
Source: EMI, Contact.
Does not include NZAS
National electricity demand (TWh)
Regional
change (%)
FY23vs FY22
Source: EMI, Contact
Market demand
5.05.0
5.2
5.1
4.9
5.0
5.0
10.0
10.1
10.110.3
10.6
10.2
10.5
25.9
26.1
26.1
25.8
26.1
25.8
25.6
FY17FY18
41.2
FY19FY22
1
FY20
South Island (ex NZAS)
North Island
FY21FY23
NZAS
40.9
41.1
41.3
41.4
41.6
41.1
0%
0%
New Zealand electricity demand is flat on FY22 in spite of industrial closures and warmer weather impacts
Total national electricity demand increased
by 0.1 TWh (0.23% from FY22):
•The decrease in Northland regional
demand (11%) was a result of Marsden
Point refinery converting to an import-
only terminal from April 2022 – a
reduction of 177GWh on the prior year.
•East Coast regional demand is down
10% as Pan Pac’s Whirinaki site is
closed until further notice, due to
impacts from flooding from Cyclone
Gabrielle.
•A dry summer for the South Island in
2022/23 saw higher irrigation demand
at major South Island irrigation demand
nodes.
•Removing the impact from known
major industrial variations, unusual
weather and other known impacts,
indicates that underlying demand is up
~1-2% on FY22.
2%
0%
(1%)
6%
(1%)
0%
0%
3%
3%
7%
1%
(1%)
1%
1%
(11%)
2%
2%
2%
1
FY22 demand data has been restated to be consistent with the most recent demand data released by EMI.
(10%)

9
Hydro generation was up 13%
when compared to FY22,
driven by~42% uplift in the
North Island (South Island up
~3%).
Impacts included:
•
Lower spot wholesale
prices.
•
Higher price separation
between North and South
Islands.
•
Limited need for thermal
generation and lower
industry carbon emissions.
Wind generation has stepped
up with Turitea coming online.

Generation by type (TWh)
Strong hydro inflows in FY23 saw actual storage levels higher than mean throughout the year, reducing
reliance on gas and coal.
Source: EMI & MBIE
Source: NZX
0.0
1.0
0.5
3.0
1.5
2.5
2.0
3.5
4.0
4.5
Jul-
21
Dec-
21
Jul-
22
Dec-
22
Jun-
23
Mean
Actual
1H221H23
Storage
TWh
National hydro storage
Carbon emissions (mT)
1
Carbon emissions for FY23 Apr-Jun quarter has been estimated using historic conversion rates with actual generation data.
Hydrology significantly impacted generation mix
Fuel supply
High hydro inflows limited the need for thermal generation
2H232H22
The reduction in carbon emissions of 1.6mT (42%) CO2-e was due to the
decrease in coal and gas generation year on year.
3.3
3.7
3.1
1.8
2.1
2.5
7.2
7.3
7.1
22.5
24.0
27.0
3.1
5.2
4.9
3.1
FY23FY21
Wind
1.2
FY22
0.5
Gas
Coal
Hydro
Geothermal
Other nonidentified
generation
43.1
43.2
43.2
6.03.82.2
1

10
10
Aluminium
Demand
Short-term external factors that
can influence the market
Changes as at 30 June 2023
in comparison to 30 June 2022
Short-term
wholesale
electricity
prices
Technical Working Group
concluded that 4PJ of stored
gas at AGS is unavailable for
immediate use
Drilling campaigns on major
fields undertaken, ultimate
results less than envisaged at
2022 reserves assessment
Carbon prices down 85% to
$41/New Zealand Unit
Government has announced
it will apply Climate Change
Commission advice on ETS
settings from December 2023
Methanol pricing at US$281/t
(down 30%)
Methanex outage allowed
summer to winter shape in
gas supply as hydro
conditions transpired and
AGS limitations were felt
Demand was
flat year on year
Aluminium prices lower
(-$440/t, down 13%)
Decrease in coal prices
(-US$236/t, down158%)
Forward wholesale pricing continues to reflect
high fuel cost and availability risk
Record rainfall led to above
mean hydro storage over
the last 12 months.
Controlled storage at ~130%
of mean (~800 GWh above
mean) in June
Wholesale and futures electricity pricing ($/MWh)
Wholesale market
0
50
100
150
200
250
300
Jun-
17
Jun-
14
Jun-
12
Jun-
13
Jun-
15
Jun-
18
Jun-
16
Jun-
19
Jun-
20
Jun-
21
Jun-
22
Jun-
23
10 year
average
spot price =
$99 /MWh
Short-dated futures (<12 months)
Long-dated futures (>12 months)
Monthly average spot price
Source: EMI wholesale pricing
While some short-term inputs to wholesale pricing have softened, notably spot Newcastle coal and New Zealand carbon unit prices, fuel price volatility and availability risk remain as drivers of forward wholesale prices,
with expected future marginal thermal costs still supporting the forward electricity price path. Domestically, strong hydrology conditions over the past 12 months have masked this and have suppressed wholesale electricity
prices. Fundamental requirement for thermal generation to support a hydro dominated electricity system supports forward electricity prices..

11
11
•Competition remains intense despite sustained high wholesale futures prices.
Market churn continues to reflect this with switching at 19%.
•Tier 1 retailers have a seen a 1% increase in market share to ~85% (84%
June-21 & 85% June-23). This is largely due to added connections as
household formation contributed to a continued ~1% p .a. growth in ICPs.
•Tier 2 retailer growth rates have been impacted due to thesharp lift in
wholesale energy prices resulting in a 1% decline in market share to ~15%
(16% June-21).
•Mercury purchased the Trustpowerretail business in FY22 and is now the
largest retailer by ICP (26% market share).
•2degrees and Vocusmerged on 1 June 2022 becoming the third largest telco,
while also providing energyproducts. Since acquisition, 2Degrees has grown
connections by 12k and are now the leading Tier 2 in electricity connections.
•Contact electricity connections +15k from June 2021 to June 2023 equating to
19% market share.
Change in customer electricity connections (000s)
30 June 2021 –30 June 2023
2yr % change2yr ICP delta (1000s)
Retail electricity tariff changes (c/ kWh)
Tier 2: -8k connections
•Increasing wholesale energy and network costs have resulted in a lift in
Residential electricity tariffs with the compound annual growth rate of 2%
across the last fiveyearsto March 2023.
•Average tariff increases for the year to March 2023 of 4.3% werematerially
below consumer price inflation (~7%)
1
, with households largely insulated
from increasinginput costs due to retailers’ longer-term view of pricing that
rides through short-term volatility.
•Input cost pressure for retailers is expected to remain with continued firming
future wholesale prices and significant network cost increases due to the 1
April 2025 price regulation reset. Retailers’ pricing will need to increase in
order to recover these rising costs.
12 months
ended:
Tier 1: +64k connections
Source: EMI
Source: MBIE
7%
4%
-1%
2%
13%
-8%
11%
-5
10
15
5
35
-15
-20
0
40
ManawaGenesisContact
4%
Mercury/Trust
Power
MeridianFlick
-14%
31%
Electric
Kiwi
Other
-4%
Pulse2Degrees/
Vocus
Nova
16.5
16.8
18.2
18.6
19.5
12.5
12.3
11.1
11.6
12.0
Mar-23Mar-19Mar-20Mar-21Mar-22
29.129.1
29.4
30.2
31.5
+2%
Retail competition remains intense
Retail electricity market
A wide range of market players continue with very competitivepricing despite rising costs
Lines (c/kWh)Energy & Other (c/kWh)
2
1
Stats NZ CIP index increase in the 12 months to March 2023.

12
Topical regulatory matters
Wholesale market
security
Energy
Strategy
Theme
Contact Approach
Timing
Battery project
(Project Onslow)
Lines assets
regulation / investment
Decarbonisation
incentives
Resource
management reform
Elevated futures pricing and
peak volatility is placing
pressure on unhedged energy
intensive industries.
Industry, Transpowerand the
EA paying close attention to
capacity this year and beyond.
Government developing NZ
Energy Strategy to address
strategic challenges in the
energy sector and signal
pathways away from fossil fuels.
Expected to account for Energy
Hardship considerations.
Government is investigating
solutions to NZ’s dry year
electricity problem.
Potential solutions include
pumped hydro, or a portfolio
approach using a range of
technologies.
Government will implement
CCC recommendations on
ETS auction settings in
December 2024.
GIDI
2
funding has targeted
large emitters. May be
discontinued if there is a
change in government.

Five discussion papers
released 9
th
August 2023.
NZ Energy Strategy due for
completion by end of 2024.
Engagement ongoing.
Contact targeting 10.3TWh of
renewables and 100MW
battery by FY27.
Investment in new renewables,
storage and demand response.
Long term contracts to smooth
price volatility.
Engagement with EA on long
term impacts of price volatility.
Contact’s focus on building new renewable generation, flexible storage and customer-focused demand response solutions
is well aligned with the political and societal imperative to deliver net zero for NZ by 2050. Orderly decarbonisation of
Contact’s portfolio is underway, with a focus on system security and affordability at each junction.
Working with electricity industry
to establish near-term actions
to implement the
complementary plan set out in
BCG’s report “the Future is
Electric”.
Orderly decarbonisationof own
portfolio. Focus on energy
security and affordability.
Detailed business case
presented to cabinet soon
to inform on which options
to undertake.
FID expected in 2027/28.
Sufficient line capacity is
critical to decarbonisation,
however, must be balanced
against the impact on
consumers.
Recommendsregulatory
changes to reduce connection
costs aiding electrification
projects.
Supportive of further analysis
of NZ’s dry year risk.
Recommends a market-led
solution.
Draft decision on 2025-30
revenue caps due in May
2024, and a final decision in
November 2024.
ETS requires stability to
remain a credible tool to
encourage decarbonisation.
Direct government support for
decarbonisation projects is an
important complement to the
ETS costs. We will continue to
work with government to find
opportunities.
Decisions on ETS forestry
credits are expected post
election.
Applicants can apply for GIDI
funding at any time.
Government is replacing the
RMA
3
with the Natural and
Built Environment Bill and the
Spatial Planning Bill, as well
as, refreshing the national
policy statement for renewable
electricity generation (NPS-
REG).
Contact has advocated for a
balance between
environmental effects and
the need to decarboniseour
economy.
Current draft Bills go some
way towards addressing our
concerns, and draft NPS-
REG looks promising.
.
Bills are expected to be
passed before the general
election (October), but there
will be a transition period of
~7-10 years.
1
Note $22bn refers to additional capital spend required out to 2030. Additional capital
spend required on distribution infrastructure out to 2050 is $71bn.
2
Government Investment in Decarbonisation
3
Resource Management Act
Government price regulation of
EDBs and Transpowerfor
2025-30.
BCG report found a need for
$22bn
1
of additional capital
spend on distribution
infrastructure by 2030 to meet
NZ’s decarbonisationgoals.

13
Financial
results and
outlook

14
Key themes from the financial results
A strong second half meant that
we outperformed our updated
guidance at 1H23 of $530m and
our original guidance
Key accounting topics:
Recognised onerous contract
provision and applied updated
guidance on IFRS 9

Sales channels repricing to better
align with wholesale market,
further opportunity exists
Cash conversion has decreased
with record low thermal generation
and higher SIB capex as guided
Provisions increased to reflect
portfolio changes and associated
decommissioning
Regulated asset base cost increases will
be a key consideration for the industry as
this could slow decarbonisation

15
Profit ($m)
Excluding the onerous contract provision, EBITDAF up $27m (underlying) largely reflecting the better
alignment of long-term channel prices to the wholesale market
Profit of $127m for FY23
EBITDAF ($m)
Driven by higher
unit price of
carbon and
decrease in
thermal efficiency
due to a higher
proportion of Te
Rapa and Peaker
generation
Higher C&I re-
pricing and
lower location
losses partially
offset by lower
spot and CFD
prices
Renewables
down 119 GWh
mainly due to a
decrease in
geothermal
generation due to
outages
(impact
calculated at
thermal SRMC)
Fixed costs higher
with increase in
other operating
costs (-$23m) and
higher electricity
transmission costs
(-$4m) from the
removal of ACOT
7
43
1
FY23 results
FY22 profit
Net interest
costs
EBITDAF
1
Depreciation
& Amortisation
Tax
Realised
changes in
FV of market
derivatives
FY22
EBITDAF
1
1. Renewables
4. Gas, carbon and
acquired
generation price
7. Fixed
costs
FY23 EBITDAF
before and
after onerous
contract provision
113
9
537
14
12
24
9
46
18
27
460
573
546
+27
2. Net
volume
5% increase
in long-term
channel
(retail,
strategic fixed
price) prices,
aligning to
rising
wholesale
market costs
2
Other income
is up due to
the gain on
sale from Te
Rapa, an
increase in
gas gross
margin and
other
6
3. Market
channel
price
2
FY23 profit
before and
after onerous
contract
provision
Onerous contract provision before tax
Reported EBITDAF
Onerous contract provision after tax
Reported profit
182
127
27
38
84
-18
211
-2
-11
-5
+29
5. Long-term
channel
price
6. Other
income
An 11%
reduction in
sales
volumes
outweighed
the cost
benefit of
reduced
generation
volumes yoy
5
1
Contact has made reclassifications to better align with IFRIC guidance on IFRS 9 resulting in realisedgains/losses from market derivatives not in a hedge relationship (includes market making activity) no longer
being reported in operating income (EBITDAF). FY22 figures restated accordingly.
2
Market channel pricing includes Includes reduced $/MWh location losses resulting from soft spot wholesale pricing
All figures are exclusive of the impacts of the onerous contract provision for AGS. Impacts of the onerous contract are as follows, EBITDAF (-$113m), interest (-$3m), tax (+$32m), NOPAT (-$84m).
Unrealised
changes in FV
of financial
instruments

16
Wholesale EBITDAF
1
(underlying, $m)
Retail EBITDAF ($m)
Corporate / unallocated costs ($m)
Business performance by segment
EBITDAF (underlying) up by $27m
Refer to slides 17 - 19
Refer to slide 20
81
43
49
9
548
FY22Generation
costs
(including
acquired
generation)
Total
contracted
revenue
Trading,
merchant
revenue
and losses
632
FY23
557
632
+75
17
-14
58
FY22
95
1
Electricity
Volumes
Electricity
Prices
6
Other
products
2
1
OpexFY23
-31
Electricity gross margin
(-$36m)
Electricity
and network
cost inflation
Price recovery
2
Other products includes retail gas and broadband gross margins and gains
on sale of legacy meter assets
FY23 results: Segmental performance
-28
-44
FY23
One-offs
4
FY22
4
6
2
FY22
One-offs
Inflation
(6%)
3
Growth and
sustainability
FY23
-16
1
Simply and Western included within Wholesale EBITDAF.
Underlying EBITDAF is shown excluding a net $113 million onerous contract provision
expense for AGS. Contact has made reclassifications to better align with IFRIC guidance
on IFRS 9 resulting in realisedgains/losses from market derivatives not in a hedge
relationship (includes market making activity) no longer being reported in operating
income (EBITDAF). FY22 figures restated accordingly.
One-off movements from FY22 include the Holidays Act
provision reversal and SaaS asset write off (together totaling
$6m). FY23 included execution programme setup costs and
industry report ($4m).
3
Stats NZ CPI increase in the 12 months to June 2023.

17
Electricity generated or acquired (GWh)
Costs down $81mon reduced thermal and acquired generation volumes
FY22FY23
Electricity generated or acquired costs ($m)
Generation costs
FY23 results: Wholesale business
Gas and diesel
Acquired
Thermal
Renewable
Gas storage
Carbon costs
Electricity and gas
transmission and levies
Other operating costs
Generation volumes
•
Hydro generation of 3,919GWh was down 21GWh (1%) on
FY22 and came in slightly above mean (3,900GWh) following a
strong hydro sequence in the final quarter.
•
Geothermal volumes were down 98GWh on FY22 (3%),
65GWh below mean (3,250GWh), as a result of the 5 yearly
Wairākeiplant outage and an unplanned outage at TeHuka.
•
Significant country-wide rainfall sequence resulted in the
wettest year on record in the North Island and the wettest year
in New Zealand post-market. Thermal generation of 517GWh
was down 54% (610GWh) on FY22 and was Contact’s lowest
thermal generation on record. ​
Costs
•
Renewable generation costs were up $7m (6%) on FY22 due
to the removal of ACOT payment for Te Huka, higher unit
carbon costs on geothermal and inflationary pressures pushing
up operating costs.
•
Thermalgeneration costs, excluding the onerous contract
provision expense for AGS ($113m) were down $51m (29%)
on significantly reduced thermal volumes.
•
Thermal fuel costs rose to $127/MWh (FY22: $109/MWh). With
thermal efficiency decreased due to a higher proportion of Te
Rapa and Peaker generation (FY22: 9.7 TJ/MWh, FY23: 11.8
TJ/MWh) and higher unit price of carbon (FY22 $40/unit, FY23
$48/unit), slightly offset by lower gas costs (FY22: $8.3/GJ,
FY23: $7.9/GJ).
3,283
3,185
3,940
3,919
1,127
517
389
Geothermal
FY22
Hydro
150
8,739
FY23
Acquired
Thermal
7,772
99
105
103
30
110
32
172
92
121
50
55
38
18
26
24
26
55
18
7
8
338
Generation
type
257
Cost
type
Generation
type
Cost
type
338
257
-81
87%
Renewable % of
own generation
93%
$38.7/MWh
$33.1/MWh
*Gas storage costs exclude the FY23 $113m onerous contract provision expense
for AGS.
Development
Acquired generation
costs

18
3727GWh
$129.5/MWh
Contracted
revenue ($m)
Diversified mix of long-term and ASX linked sales channels
1437GWh
$132.0/MWh
+38GWh
+$22.4/MWh
-660GWh
-$6.9/MWh
•Fixed price variable volume electricity sales to the Retail segment and C&I customers
ended 198 GWh higher than FY22 (+$22m). Prices were up $22.50/MWh to $132.50/MWh
(+$109m), reflecting higher wholesale prices over the three preceding years.
•Strategic fixed price sales were 26GWh higher than FY22 (+$1m), reflecting more volume
under the NZAS support contract. Prices to strategic fixed priced sales remained in line with
prior period ($0m) as inflationary adjustments to long-term sales were not enough to offset
the mix change from proportionally higher NZAS volume.
•CFD sales volumes were down by 660GWh (-$92m) on lower renewable generation, lower
wholesale prices and reduced thermal sales from thermal generation. Prices were down by
$7/MWh reflecting hydro inflows (-$10m).
•Operating costs to support commercial and industrial customers were lower (+$1m) as
Simply acquisition synergies were captured.
•Steam sales up on higher carbon price (+$2m).
•Other income was higher (+$9m) mainly due to a gain on sale of Te Rapa of $7m.
Wholesale contracted revenue
24
1099GWh
$137.2.0/MWh
+159GWh
+$22.1/MWh
395
482
108
151
291
190
75
76
33
35
3
Other net income
-12
FY22
1
12
-11
FY23
Steam sales
Strategic fixed price sales
CFD sales
C&I net price
Retail segment sales
C&I channel
and decarbonisation
support costs
893
936
+43
FY23 results: Wholesale business
1415GWh
$53.9/MWh
+26GWh
$0.0/MWh
Year-on-year
changes to
volume and price
FY23 volumes
and price
1
Contact has made reclassifications to better align with IFRIC guidance on IFRS 9 resulting in realisedgains/losses from market derivatives not in a hedge relationship (includes market making activity) no longer being reported in operating
income (EBITDAF). FY22 figures restated accordingly.

19
Trading EBITDAF ($m)Long / short position (GWh)
$137.6/MWh
7.7%
($10.6 / MWh)
9.0%
($7.4 / MWh)
•Wholesale market conditions
(average OTA price of $86.71/
MWh
1
) did not support additional
CFD sales nor length that was
thermal generation backed.
•Contact ran significantly short
through Q4 FY23 to take
advantage of soft spot wholesale
market conditions, saving fuel
costs.
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
86
-85
-56
-48
FY23FY22
1
8
625
93
-8,033
7,600
FY23
-7,600
8,033
FY22
625
93
FY23 results: Wholesale business
LWAP/
GWAP
losses
1
Source: EMI

20
1
Retail business performance
EBITDAF ($m)
Managing through elevated wholesale input costs while growing market share through a multi-product strategy
Revenue & Tariff
1
($m)
FY22FY23Variance
$m$mTariff¹$mTariff
Electricity gross revenue
8729422706917
PPD
2
not taken
33(0)
Incentives paid
(5)(4)0
Net revenue (cash)
8719402707017
Capitalised incentives
51
Amortised incentives
(6)(5)
Net revenue (P&L)
8699372696817
Gas revenue
82903586
Broadband revenue
53667014(1)
Other income
792
Total revenue
1,0111,10291
Contract Asset (closing)
74(3)
# of connections (closing)
3
574k584k10k
Cost to serve/connection
$123$120($3)
1
Tariff is $/MWh for electricity, $/GJ for gas and $ per month per customer connection for broadband
2
Prompt Payment Discount
3
Retail connections only, excludes Simply Energy
7
6
68
32
9
7
9
-68
-69
FY22FY23
17
-14
3
Gross Margin (GM) is Revenue less Cost of Goods (Networks,
meters, levies, energy, carbon and broadband)
FY23 results: Retail business
Other income
Gas GM
Electricity GM
Broadband GM
Other operating
expenses
Retail margins have contracted, driven by sustained
high wholesale futures prices.
•Retail EBITDAF decreased by $31m on FY22 largely
driven by the $83m increase in electricity costs that
were not fully passed through to customers.
The Retail business has continued to insulate customers
from rising input costs by keeping the average tariff
increase largely in line with consumer price inflation.
•The average Retail tariff increased by 6.7% reflecting
targeted retail price rises to partially offset rising
wholesale and network cost increases.
•Around 83% of customers received a price increase
in the last 12 months.
•Retail energy tariffs will need to rise to recover the
continued firming future wholesale prices and
significant network cost increases due to the 1 April
2025 price regulation reset.
Connection growth slowed in FY23 given increased
focus on multiproduct connections and value in
electricity.
•Total connections still +10k on FY22primarily
through continued growth in broadband.
•Multiproduct customers up 10% on FY22, assisted
by new fixed wireless broadband and Dream Charge
EV products launched.
Cost to serve – digitised interactions continue to grow
driving improvements in cost to serve per connection
(down $3/connection on FY22) and customer
experience (NPS +4 points on FY22).

21
Other operating
cost movement
($m)
Base
movement
Non-recurring
•FY22 one-off impacts relate to the release of Holidays Act credit and early-
stage development costs which have shifted into the capitalisationphase of
the projects in FY23.
•FY23 one-off impacts represent strategic execution set up costs, Contact’s
share of BCG industry report, cost of retaining TeRapa employees until plant
closure and cyclone recovery costs incurred at Whirinakiand Geothermal
sites. This has been offset by cost deferrals linked to reprioritisation of activity.
Base movement
•General inflation of 5-9% impacting operating costs. These have been seen
across the business, including labour cost and insurance inflation.
•Headwinds include increase in travel expenditure in a post-Covid environment.
Growth and sustainability
•$1m incremental investment related to retail connection growth.
•Operating costs to deliver on strategic growth priorities including;
•Ongoing costs of transformation.
•ESG and compliance opexinvestments to increase capability,
furthering ESG outcomes.
•Targeted leadership development training, and costs associated with “Grow
your Whanau” policy implementation.
Operating costs up on investments in growth
strategy and cost pressures
Base savings
General cost inflation
Invest in
growth and
sustainability
FY23 results: Operating costs
Headwinds
FY22 One-off Impacts
FY23 One-off Impacts
3
4
4
4
3
12
FY22One Off ImpactsUnderlyingGrowth and
sustainability
FY23
210
7
11
233
Non-recurring

22
•Higher underlying EBITDAF on execution of long-term channel prices increases.
•Working capital increase of $38m in FY23. This relates to higher levels of gas and carbon unit
inventory following lower thermal generation in FY23 as a result of strong national hydrology.
•Tax paid is up $16m on higher provisional tax payments based on strong FY21 earnings.
•Stay-in-business capital expenditure (cash) increase of $34m is linked to accelerated spending
identified to support higher asset availability and output as well as an SAP systems upgrade
project. Accelerated SIB capex programmespend in the period totalled$38m.
12 months
ended
30 June 2023
12 months
ended
30 June 2022
Comparison
against FY22
EBITDAF (underlying
1
)$573m$546m
1
↑$27m
Working capital changes($55m)($17m)↓($38m)
Tax paid($105m)($89m)↓($16m)
Interest paid, net of interest capitalised($25m)($28m)↑$3m
SIB capital expenditure($113m)($79m)↓($34m)
Non-cash items included in EBITDAF$7m($3m)↑$10m
Operating free cash flow$282m$330m
1
↓($48m)
Operating free cash flow per share36.0 c42.4 c
1
↓(6.4 c)
Cash conversion (OpFCF / EBITDAF)49%61%↓(12%)
Return on invested capital (ROIC)
Cash conversion for FY23 impacted by higher tax paid, SIB capex and an increase in gas and carbon unit inventory
Cash flow and capital expenditure
Sources and uses of cash ($m)
FY23 results: Cash flow
191148142
200173
207
NOPAT - $m
2
NOPAT (4-year average) /Average IC (4-year average)
3
NOPAT (FY)/Average IC (FY)
4
Net working capital adjusted to remove current borrowings, current net derivatives and excess cash above $50m.
Long-term assets adjusted to remove non-current derivatives.
Average = Invested capital (opening + closing balance) / 2
1
Contact has made reclassifications to better align with IFRIC guidance on IFRS 9 resulting in realisedgains/losses from market
derivatives not in a hedge relationship (includes market making activity) no longer being reported in operating income
(EBITDAF). FY22 figures restated accordingly.
282
273
4
28
22
442
Sources
16
30
27
472
Uses
798798
Cash Movement
Debt drawdown
OpFCF
DRP
Sale of asset
Strategic investments / acquisitions
Growth investment
Dividends paid
Realisedlosses on market derivatives
Financing cost / cost of debt issuance
0
1
2
3
4
2.8%
3.2%
2.3%
3.5%
3.6%
3.6%
3.5%
ROIC (average)
2
ROIC (FY)
3
5,257
5,097
4,814
4,543
4,448
4,484
4,872
FY22FY21FY17FY23FY18
Average IC
($m)
4
FY19FY20
122
Net operating profit after taxes (NOPAT) / Invested capital (IC)

23
Growth capital expenditure
Up to
30 June 2022
12 months ended
30 June 2023
Remaining under
current
approvals
Total
Tauhara$408m$340m$132m$880m
Te Huka 3$28m$88m$184m$300m
GeoFuture-$12m$102m$114m
Wind-$5m$5m$10m
Capitalised
interest
$55m$44m$60m$159m
Total$491m$490m$483$1,463m
FY23 results: Growth capital expenditure
Step-up in growth capital expenditure in FY23 reflects the advancing nature of Contact’s renewable
development projects
•The Tauhara geothermal project is due for completion in Q4 2023, with the
remaining growth capex all scheduled to be incurred in FY24.
•The construction of Te Huka 3 is well underway and is due to be completed in Q4
2024. The remaining growth capex will fall across FY24 and FY25.
•Remaining spend on GeoFuture and Wind projects reflects current pre-FID
approval levels and will be updated after final board investment decisions, as
applicable.
•For major growth projects we capitalise interest from the time of Final Investment
Decision (FID) or significant pre-FID works through to commissioning on a rate that
reflects the average portfolio interest rate.
Growth capital expenditure ($m)

24
•Face value of borrowings (excl. leases) increased by
$449m to $1,474m from 30 June 2022.
•Two green bonds were issued during the year, partly
to refinance a maturing $100m retail bond in
November with the remainder to fund the ongoing
construction of the TeHukaand Tauhara geothermal
stations.
•All facilities are classified green under Contact’s
sustainable finance framework, and the bank facilities
are sustainably linked with alignment to the
Contact26 strategy to lead decarbonisationin New
Zealand.
•Contact’s planning aligns with maintaining its
investment grade credit rating. This requires net debt
to EBITDAF to remain below 3.0x over a sustained
period. Of note, S&P calculates EBITDAF on a
smoothed basis, with a recent re-weighting toward
future periods reflecting Contact’s current growth
profile.
•Point estimate net debt to EBITDAF is currently 2.2x
and Contact’s EBITDAF outlook, DRP and capacity
for additional hybrid bonds provide the ability to
mange this metric effectively.
A green and sustainably-linked debt portfolio aligned to our Contact26 strategy
Closing net debt ($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 2023
Strong balance sheet
1
Includes $51m 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 the last 12 months.
1,410
990
1,036
774
1,025
1,474
-150
-168
FY19
38
-3
FY18
25
-44-47
22
FY20
21
FY21
25
1,445
FY23
1
FY22
49
-140
968
1,383
1,014
645
882
Cash on handLease obligationsBorrowings
67
225
153
100
136
350
300
150
350
250
FY25
7
FY24
7
FY29
22
7
FY26
7
FY27
4
FY28FY30-
FY52
160
257
493
357
275
367
Undrawn bank facilitiesDomestic bonds
Drawn bank facilitiesUSPP
NEXI
Capital bonds
3.1
2.3
2.4
1.2
1.5
2.2
FY22FY18FY19FY20FY21FY23
1,476
1,207
1,031
963
902
1,329
5.2%
5.4%
5.1%
FY18FY21
5.2%
FY19FY20
5.3%
FY22
5.8%
FY23
Average gross interestAverage gross debt
FY23 results: Key balance sheet metrics

25
Dividend for FY23 of 35 cents per share
•Final dividend of 21 cents per share is imputed up to 86% or 18 cents per share for qualifying shareholders. This
represents a pay-out of 97% of FY23 operating free cash flow per share and 83% of the average operating free cash
flow over the preceding 4 financial years (FY19-FY22)
•The dividend policy is to pay-out between 80-100% of average operating free cash flow of the preceding four years.
•Record date of 8 September 2023; payment date of 26 September 2023.
•The NZD/AUD exchange rate used for the payment of Australian dollar dividends will be set on 15 September 2023.
Dividend for FY23 in line with performance
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.
•There will be no discount offered for the FY23 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 11 September 2023 to confirm participation in the plan.
•Trading period for setting price for DRP is 7 September 2023 to 13 September 2023. DRP strike price will be
announced: 15 September 2023.
Ordinary dividends ($m)
Declared
Final dividend
Interim dividend
% pay-out of annual operating free cash flow
3939
39
35
35
cps
97%
72%
82%
97%
Operating free cash flow
Average operating cash flow for the preceding four financial years
Dividend policy range: 80-100% of average operating free cash flow
for the preceding four years
324
84%
259
247
FY19
309
325
260
FY20FY21
326
FY22
261
333
83%
266
FY23
318
256
87%
2
FY24
341290
371
➢Annual operating
free cash flow
100%
80%
Dividend level
as a % of preceeding
4yr operating fcf
165165
163163
164
115115
109109
109
280
FY22FY20FY23FY19
272
280
FY21
272
273
cps
82%
330
1
282
1
Contact has made reclassifications to better align with IFRIC guidance on IFRS 9 resulting in realisedgains/losses from market derivatives not in a hedge relationship (includes market making activity) no longer being reported in operating income
(EBITDAF). FY22 figures restated accordingly.
2
This calculation is based on the minimum target ordinary dividend of 35 cps. Guidancewill be confirmed no later than the 1H24 results, given potential for long term Tiwai supply agreement to be reached.

26
26
Uplifts in Contact’s normalisedand expected EBITDAF
have been driven by pricing and channel management
57
29
16
16
24
Other
operating
costs and
income
FY24
guidance
(ex. Tauhara
online)
1
Gas, carbon
and risk
management
costs
Market
channel
price
Long-term
channel
price
6
Net impact
of Te
Rapa sale
0
FY23
guidance
Tauhara
fixed costs
550
600
Net volume
impact
5
Transmission,
levies and
storage costs
50
¹ See slide 34 of for assumptions underpinning FY24 normalisedand expected earnings
2
Contact has made reclassifications to better align with IFRIC guidance on IFRS 9 resulting in realisedgains/losses from market derivatives not in a hedge relationship (includes market making activity) no
longer being reported in operating income (EBITDAF). FY22 figures restated accordingly.
Normalised and expected EBITDAF ($ million) –excluding Tauhara online
FY24 guidance does not include EBITDAF from Tauhara online
480
520
550
600
553
546
573
FY22FY21FY23FY24
Actual result delivered
Guidance (at beginning of the year)
Guidance vs Actual
Like-for-like increase of $50m (9%) in year-on-year guidance
Strong track record of delivering
performance above guidance
Guidance CAGR FY21 to FY24 (8% p.a.)

27
27
Guidance below EBITDAF
FY23 guidanceFY23 resultFY24 guidanceCommentary
Stay in Business Capex
$110m-120m$113m$115m - $125m
1
Stay in business accelerated programme
(cash)
$38m$55m - $60m
As at end of FY23 we had spent $65m out of the $150m accelerated stay in
business capex programme
2
.
Stay in business capital expenditure (cash)
BAU
$79m$60m - $65mSustainable SIB capex remains $65m p.a.
Growth capital expenditure (cash)
3
$465m-$565m$472m$400m - $500mGrowth capital for Tauhara, Te Huka, GeoFuture and Wind.
Depreciation and amortisation
$220m-230m$224m$230m - $240mReflects higher mix of short life-cycle assets.
Net interest (accounting)
$35m-45m$41m$65m - $75m
Reduction in capitalisation of interest with Tauhara commissioning. Higher
interest rate environment and increased borrowings.
Cash interest (in operating cash flow)
$20m-30m$25m$47m - $57m
Cash taxation
$110m-120m$105m$95m – $105m
FY24 provisional payments based on FY22 results and lower final tax payment
relating to FY23.
Realised (gains) / losses on financial
instruments (cash)
$0m$27m$10m - $15mIncluding (gains) / losses on ASX market making.
Corporate costs
$42m$44m$48mInflation and growth.
Target ordinary dividend per share
35 cps35 cpsMinimum 35 cps
Guidance will be confirmed no later than the 1H24 results, given potential for long
term Tiwai supply agreement to be reached.
1
FY24 guidance range is gross i.e.before the netting of insurance proceeds of $15m.
2
Accelerated stay in business programmetotal is stated net of insurance proceeds of $15m. The capex and insurance income will be separately disclosed in the financial statements.
3
Growth capitalexpenditure includes capitalisedinterest.

28
Progress on
Strategy

29
Grid-scale battery investment lined up
Contact is planning to invest in renewable energy flexibility in the North Island
Auckland
Wellington
Christchurch
Glenbrook
Stratford
Battery
location
options
Battery investment key metrics
1
Battery capacity
100MW
Storage duration /
discharge
2 hr / ~200MWh
Total estimated
construction costs
~$170m
to $190m
¹ All subject to Final Investment Decisions
✓
Participation across physical,
reserve and frequency-keeping
markets.
✓
North Island location, close to retail load,
reducing North/South Island price
separation.
✓
Reduced reliance on gas
peakers.
✓
Glenbrook site preferred (subject to
consent). Stratford option already
consented.
Final Investment
Decision
1H FY24
Supports both retail growth and
offering capacity contracts to third
parties.
✓
✓
Supports new wind and solar.

30
Market leading renewable development pipeline
Contact has built a renewable electricity development pipeline of >6TWh, and is targeting 10.3TWh of
renewable generation output online by end of FY27
Consented post-FID (under construction)
Consented pre-FID (development option)
2.1
1.1
1.9
3.0
Consenting in progress
Land access secured / exclusivity
1.9
1.6
20202023
3.5
6.5TWh
Potential options
for future uplift
Planned and
consented
>2027
Tauhara
(1.4TWh)
Te Huka
(0.4TWh)
GeoFuture
(1.4TWh)
Roxburgh
(45GWh
2
uplift)
Planned and consented renewable energy development projects
1
Expected generation (indicative):
Potential options for future uplift
Expected generation (indicative):
Tauhara
stage 2
(0.7TWh)
Remaining
capacity
Wairākei
closure
(1.0TWh)
Note: Timeline is shown based on calendar years.
1
All uncommitted investment / closures are subject to Board investment decisions. The Tauhara, TeHukaand Roxburgh investments have been committed to.
2
45GWh p.a. uplift is based on mean hydrology conditions.
Kōwhai Park
(Solar)
(0.3TWh)
Glorit
(Solar)
(0.3TWh)
20242025202620272023
Southland
(Wind)
(0.9-1.2TWh)
Battery
(100MW)

31
Our operational plan
FY24
Conclude NZAS extension negotiations
with improved long-term pricing.
FID for one Green Chemical deal.
Achieve FID for GeoFutureand Kōwhai
Park solar.
On track FID for North Island solar.
On track FID for wind.
Net zero roadmaps agreed (Scope 1 and 2).
Investment plans for further carbon offsets.
Electricity net price up by around 5%.
Greater than 615k connections.
Maintain leading cost to serve position.
Grow renewable
development
Decarbonise
our portfolio
Create
outstanding
customer
experiences
Strategic theme
Grow
Demand
Tauhara operational Q4 2023.
Final Investment Decision on BESS
(battery).
Facilitate at least 25MW of new demand.
Final Investment Decision on BESS
(battery).
Sustained entry into the DJSI.
Significantly grow non-energy gross margin.
Further expansion of “It’s good to be home”
brand position.
Pilot launch of Contact Mobile.
What you can expect in the next 12 months

32
Questions

33
Supporting
materials

34
Normalised and expected FY24 EBITDAF
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
Hydro mean3,900GWh$0/MWh-$0m
Geothermal average3,250GWh$5/MWh-$16m
Maximum thermal1,800GWh$120/MWh⁴-$216m
Acquired0GWh$0/MWh-$0m
-$232m
Length⁵$53mTransmission/Storage-$70m
Location losses⁶-$52mOperating expenses-$257m
Total$1mTotal-$328m
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, broadband 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 p.a. assumed
6.Locational losses of 4.3% on spot purchases and settlement of CFDs sold at a
wholesale price of $139/MWh
•Fuel is natural gas and carbon costs
•Retail volume contracted competitive risk remains on pricing achieved (FY23 $138.1/MWh)
2,250
250Channel choices maximise
long term value¹
1
Net price² driven by
best commercial practices
2
x
=
FY assumptions that deliver expected & normalised EBITDAF for FY24 (excluding Tauhara online)
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
=
=
=
=
=
=
=
1,020
230
0
3,700
1,150
CFDs
C&I
Retail
Strategic fixed
$142/
MWh
$142/
MWh
$144/
MWh**
ContractedUncontracted
1,159
-232
-328
1
600
x
Jan-24Jul-23Jul-24Sep-23Nov-23Mar-24May-24
126
122
138
126
90
153
126
96
119
131
103
119
87
126
68
101
97
81
154154154154
126
154
ASX Futures $/MWh
monthly contracts
At 3 Aug 2023
$50/
MWh
OTA
BEN
•Note, these figures are subject to rounding.
•Dependent on volumes from Tauhara, guidance to be updated when Tauhara comes online.
Guidance to be updated for Tauhara once online

35
Strategic fixed price1,450GWh$54/MWh $78m
CFDs1,600GWh$135/MWh$216m
C&I1,200GWh$140/MWh$168m
Retail3,700GWh$132/MWh$488m
Other income³$70m
$1,021m
Hydro3,900GWh$0/MWh-$0m
Geothermal3,250GWh$3/MWh-$10m
Thermal⁴1,050GWh$115/MWh-$121m
Acquired250GWh$150/MWh-$38m
-$168m
Length⁵$81mTransmission/Storage-$68m
Location losses⁶-$80mOperating expenses-$235m
Total$1mTotal-$304m
FY23 assumptions that deliver expected & normalised EBITDAF of $550m over a financial year
EBITDAF guidance reconciliation to FY23
Hydrology & Asset
availability optimise generation
3
4
Total
x
=
Access to and price of fuel* drives
financials & risk position
Lower market channel price
Normalised & Expected
Lower renewables
Other income
Actual
Renewable generation slightly below mean (-46GWh).
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, broadband gross margin and other income
4.Gas price of $7.9/GJ, carbon price of $50/unit and thermal portfolio heat rate (11.2GJ/MWh)
5.Length of 500GWh for FY23 assumed
6.Locational losses of 6.7% on spot purchases and settlement
of CFDs sold at a wholesale price of $150/MWh
Fixed costs
Received ‘loss and constraint excess’ (LCE) rebates due to
substantial price separation. Lower gas transmission charges
6
25
3
9
6
12
2
550
573
This includes a gain on the sale of Te Rapa
Normalised and expected EBITDAF assumptions
FY23 results
With reconciliation to actual performance
x
Increased long–term channel price
Price increases put through long-term channels have
outperformed expectation
Strong hydrology softened market prices however this was largely
offset by reduced $/MWh location losses
Gas, carbon, acquired generation price
Thermal efficiency 5% unfavourable with higher proportional Te Rapa
generation, partially offset by lower acquired generation costs
Generation volumes for the year were 8% below expectations
Net volume impact

36
57
43
50
57
76
942
852
939
-258
-252
-258
-265
-291
-51
-46
-76
-85
-56
-184
-152
-230
-185
-94
Variable
fuel costs
1,068
FY21
Electricity
sales revenue
FY19
1,023
FY23FY22
2
FY20
Other gross
margin
Fixed operating
costs
Location losses
505
1
446
553
546
573
Operating earnings (EBITDAF)
103
105
108
106
115
0.83
4.57
1.33
3.79
5.14
0.81
3.61
3.73
FY19
3.74
FY20FY21
3.69
1.39
FY22
1.42
FY23
4.59
4.94
5.08
RetailLong-term sales
84
83
101
117
126
FY19
1.67
0.55
2.23
1.50
0.63
1.44
0.34
FY20FY21
1.13
0.39
FY22
0.52
2.14
0.15
FY23
1.77
1.52
0.67
ThermalAcquired
Electricity sales
Variable fuel costs
11111
3.33
3.94
4.23
FY19
3.26
3.11
3.75
3.70
7.22
FY20FY21
3.28
FY22
7.49
3.92
3.19
FY23
7.08
6.81
7.10
GeothermalHydro
(i) Renewables
(ii) Thermal and acquired
93
87
131
133133
1.04
2.10
2.17
4.10
3.02
FY19
0.97
1.26
0.86
1.94
FY20
1.23
0.94
0.93
2.63
FY22FY21
0.63
5.03
1.10
1.44
0.09
FY23
4.29
3.66
Commercial and IndustrialSpot sales
CFDs
(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 ($m)
1
EBITDAF
2
1
2
1
Underlying EBITDAF excluding the impact of the sale of Rockgas (LPG business)
2
Refer to slide 43 for a definition and reconciliation of EBITDAF. Contact has made reclassifications to better align with IFRIC guidance on IFRS 9 resulting in realisedgains/losses from market derivatives not in a hedge relationship (includes market
making activity) no longer being reported in operating income (EBITDAF). FY22 figures restated accordingly.
98
96
118
117
121
7.77
9.62
8.86
9.04
8.74
Price ($/MWh)
Volume (TWh)

37
Greenhouse gas emissions
IndicatorUnitTarget
FY20
FY21FY22FY23
Direct GHG emissions (Scope 1)tC02e
45% reduction of 2018
Scope 1 and 2 emissions
by 2026 (Absolute
emissions reduction
target)
920,403
1,044,744786,842526,621
-Stationary combustiontC02e920,4031,044,537786,544526,282
-Mobile combustiontC02e
270
178297307
-Fugitive emissionstC02e429132
Indirect GHG emissions (Scope 2)tC02e
1,258
1,303
1,3991,957
Sub-total Scope 1 and 2tC02e647,443921,9351,046,047788,241528,579
Indirect GHG emissions (Scope 3)tC02e259,118317,384555,035394,784273,673​
-Category 1 –Purchased goods and servicestC02e
30% reduction of 2018
Scope 3 GHG emissions
from use of sold products
by 2026.
39,39716,699
6,3716,197​
-Category 2 – Capital goodstC02e18,05241,72657,87688,266​
-Category 3 –Fuel and energy
1
tC02e91,857330,207149,7431,050​
-Category 4 -Upstream distribution and transportationtC02e
14
27444108​
-Category 5 – WastetC02e12314910847​
-Category 6 – Business traveltC02e7192635671,274​
-Category 7 – Employee commutingtC02e606306832965​
-Category 11 –Use of sold productstC02e166,310165,259178,554175,603​
-Category 13 –Downstream leased assetstC02e306399289164​
-Category 14 – FranchisetC02e
Total Scope 1,2 and 3 emissionstC02e906,5611,239,3191,601,0821,183,025802,252
Carbon reporting
1
Contacts swaption with Genesis Energy ended 31 December 2022 and was not called during FY23.

38
Contact generation output sold to the national grid (GWh)
Generation and sales position
3,233
3,323
3,256
3,333
3,114
3,283
3,185
3,562
3,479
4,231
3,752
3,698
3,940
3,919
1,742
1,812
1,421
1,360
1,592
1,046
FY20FY21
7,543
FY17FY18FY19FY23FY22
439
Thermal
generation
Hydro
generation
Geothermal
generation
8,537
8,269
8,614
8,908
8,445
8,404
Operational data
Renewable % of
own generation
sold to grid
79%84%
84%
80%
81%
87%94%
Geothermal generation (GWh)
Te Huka
Ōhaaki
Poihipi
Wairākei
Te Mihi
FY23 geothermal generation was 98 GWh lower than FY22 as result of a Wairākei station
statutory inspection (once every 5 years), a Te Huka outage and reduced Poihipi generation to
manage fuelling restrictions.
1,184
1,372
1,382
1,415
1,240
1,386
1,380
1,121
1,062
991
1,045
1,081
1,055
998
403
411
388
335
339
331
308
336
280
310
340
299
322
323
198
198
FY21
155
FY18
189
3,323
FY17
186
FY20FY19
189
176
FY22FY23
3,233
3,283
3,257
3,333
3,114
3,185
Hydro generation (GWh)
Spill in FY23 was a result of strong hydrology inflows in the first half coming in three main rain events coupled
with some longer outages which effected our ability to generate
3,544
103
4,786
69
4,068
-28
4,276
-59
3,905
-50
5,450
-975
-1,606
FY20
-37
FY18
-148
FY19
3,479
-275
FY21
-78
FY22
75
FY23
4,231
3,752
3,919
3,698
3,940
Inflows stored include uncontrolled storage lakes
Inflows
Inflows
stored
Spill
Thermal generation (GWh)
1,020
1,071
1,013
871
1,126
673
164
495
528
207
291
234
179
148
226
211
195
195
213
190
125
83
1,439
90
1
FY18
92
FY17FY19
3
5
3
79
FY20
18
81
FY21
4
81
FY22
2
78
FY23
1,834
1,903
1,503
1,673
1,127
517
Te Rapa
Spot
Whirinaki
Te Rapa
Direct
Peakers
TCC
FY23 thermal generation volumes were 610GWh lower than FY22 as a result of the strong renewable
generation and low wholesale prices. Thermal generation accounted for 4% of total revenue in FY23
(8% in FY22) calculated as thermal pool revenue + Te Rapa direct sales as % of total revenue.

39
Plant and fuel performance
Geothermal fuel extracted at Wairākeivs consented (GWh)
Wairākei, Poihipiand TeMihi conversion effectiveness
(MWh per kTextracted)
% of geothermal fluid extractedWairakei mass extracted
80
0
100
20
40
60
100%
FY17
97%
FY22
100%
FY18
99%
FY19
100%
FY20
98%
FY21
98%
FY23
-2%
31.2
31.6
31.4
31.1
30.5
31.0
30.4
FY21FY22FY17FY18FY19FY20FY23
-2%
Geothermal fuel performance
Taranaki combined cycle (TCC)
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
FY19
37763%31%1,031115117
FY20
37788%26%871120104
FY21
37789%34%1,126193217
FY22
37784%20%673180121
FY2337785%5%16410718
Hydro
Geothermal
Stratford Peakers
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
FY19784
97%62%4,231123521
FY20784
92%54%3,75290338
FY21784
84%54%3,698167617
FY22784
83%57%3,940121478
FY2378484%57%3,91974290
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
FY19
42592%87%3,256133434
FY20
42595%89%3,33399330
FY21
42589%84%3,114175546
FY22
42597%91%3,284140458
FY23
410
1
94%89%3,18680254
TeRapa (spot generation only)
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
FY19
202
64%12%207
18538
FY20
202
80%16%291
16147
FY21
202
90%13%234
23054
FY22
202
53%10%179
21238
FY23
202
77%8%14820731
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
FY19
4196%54%19516031
FY20
4198%51%19510621
FY21
4193%58%21317437
FY22
4195%54%19014528
FY234192%30%1259412
Plant availability
Availability Factor calculation includes all station outages (Planned, Maintenance, Forced) but does not consider plant deratings.
1
Reduction in geothermal net capacity is a result of decommissioning of wells on the Wairakei steam field.
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
FY19
158
98%0%5
4722.5
FY20
158
98%0%3
2931.0
FY21
158
94%0%18
4107.5
FY22
158
95%0%4
5972.4
FY23
158
82%0%24911.2
Whirinaki

40
Haweastorage (GWh)
Gas storage (PJ)
Closing storage
Closing storage (current)
Fuel storage movements
Source: NZX hydro
158
156
256
98
175
165
260
116
252
291
352
248
300
230
324
189
324
265
-293
-253
-406
-223
-239
-230
-332
-187
-325
256
1H232H192H232H222H212H201H201H211H22
Inflows
Opening storage
Releases
98
156
175
165
260
116
252
192
5.6
4.5
5.0
6.1
5.0
5.7
7.8
4.7
2.7
0.6
1.5
2.2
0.8
1.7
2.4
0.5
2.7
1.7
-1.7
-1.0
-1.1
-1.9
-0.9
-3.5
-0.7
-0.7
-4.0
2H192H22
4.4
2H20
5.8
-0.4
2.7
1H201H212H211H221H232H23
Gas Injected
Gas Extracted
Opening Storage
5.0
6.1
5.0
7.7
3.7
4.7
Operational data
Following the completion of a joint technical working group, set up by Contact and the AhuroaGas Storage Facility (AGS) owner FlexGasin 2022,
Contact advised the market in December 2022 that approximately 4PJs of gas owned by Contact and currently stored in AGS may onlybe
available for extraction at the end of the contract in 2033. Excluding this volume, the estimated storage capacity of the facility is ~6-8PJ (P-50).
Information about the total volume of gas in the facility can be found at https://www.gasindustry.co.nz/data/gas-storage/
0
Transferred to
long-term storage
(PJ)
0
0
0
0
0
0
4
0
Long-term storage

41
Contracted gas volumes (PJ)
Uses of gas (PJ)
Gas storage monthly injections and extractions (PJ)
Contracted and stored gas
Gas injectedGas extracted
7.6
8.1
3.4
0.9
1.5
7.0
7.0
4.5
4.5
6.1
1.7
6.2
4.5
2.0
5.3
7.4
6.4
2.3
5.5
5.2
0.4
16.6
CY21CY19CY20CY22
0.0
-0.2
CY23
1
CY24
2
CY25
16.9
14.6
15.5
13.5
13.2
0.29
Oct-
22
-0.08
Aug-
22
0.43
Jul-
22
-0.03
Jan-
23
-0.02
1.08
-0.04
-0.08
Sep-
22
0.08
0.35
0.55
-0.08
Nov-
22
0.50
Feb-
23
-0.38
Dec-
22
0.26
0.21
-0.09
-0.24
-0.30
Mar-
23
Jun-
23
-0.01
0.24
0.25
-0.04
May-
23
0.20
Apr-
23
10.3
8.1
9.4
9.3
9.8
6.6
9.8
6.3
-1.1
1.1
-0.7
-2.0
3.1
-2.0
-1.0
-7.9
-5.3
-8.2
-6.7
-4.4
-6.5
-3.3
-2.7
-1.8
-1.4
-1.7
-1.4
-1.6
-1.3
-1.6
-1.1
-0.6
-1.6
-1.9
-2.7
-1.4
-0.5
-0.1
1H20
-0.5
2H23
-0.2
2H211H212H201H222H221H23
Net extraction
(injection)
Generation
Customer sales
Wholesale sales
Purchases
Short-term gasMaui
Genesis
Swap
Pohokura
Operational data
1
Maui and Pohokura volumes for CY24 reflect forecast volumes.
2
No forecast currently available for CY25. Contracted amounts shown.
Revisiting appropriate
gas contract volumes
with supplier due to
renewable build

42
Contractual fuel position sufficient to
support expected sales position
Fuel position
Portfolio requirements for thermal generation (TWh)
Scenario shown is pre-Tauhara online, backed by TCC
Gas supply and demand 2024 (PJ)
14.8PJ**
Hydro variation >>
•Hydro generation in FY12
** Assumes mix of TCC and peaker generation (portfolio heat rate (8.2GJ/MWh))
GeothermalExpected
2024
generation
from
onstream
assets
(including
losses)
Hydro in
"extreme
dry" year*
Maximum
thermal
required
"Extreme
dry" to
"mean"
year swing
Mean
thermal
required
Maximum
thermal
required
"Mean" to
"wet" year
swing
Minimum
thermal
required
Gasforecast
undercontract
14.8
13.2
2.5
3.7
Mean Thermal
Mean Year
demand
(ex-Tauhara
online
scenario)
CY24
Position
Retail
Gas in storage
17.3
17.3
Short term gas purchases
0.4
9.0
2.8
1.8
1.5
-2.9
-3.3
-1.0
-0.3
Options in a dry year:
•Access to stored water
in Hawea
•Purchase spot gas
•Stop selling
uncontracted electricity
•Acquire generation
from ASX
.
*** Revisiting appropriate gas volumes with supplier due to renewable build.

43
EBITDAF is Contact’s earnings before interest, tax, depreciation and amortisation, and changes
in fair value of financial instruments.
EBITDAF is commonly used in the electricity industry so provides a comparable measure of
Contact’s performance.
Reconciliation of statutory profit back to EBITDAF:
12 months ended
30 June 2023
12 months ended
30 June 2022
Variance on prior year
$m%
Underlying
1
ReportedReported
2
Against underlying
Profit211 127182292%
Depreciation and
amortisation
224262-38-15%
Change in fair value of
financial instruments
18-523nmf
Net interest expense38413626%
Tax expense8250711115%
EBITDAF573460546275%
Depreciation and amortisation, change in fair value of financial instruments, net interest and tax expense are
explained on the right.
Reconciliation between Profit and EBITDAF
The adjustments from EBITDAF to reported profit and
movements on FY22 are as follows:
•Depreciation and amortisation: decreased by $38m
(15%) on FY22 primarily resulting from acceleration of
depreciation for aspects of SAP due to SAP upgrade
project in FY22 and lower depreciation on TCC with lower
usage and change in useful life through to end of winter
2024.
•Net interest expense: Slightly higher than FY22 on
higher averageborrowings and higher interest rates. This
is partially offset by higher capitalisedinterest on Tauhara
and TeHukaprojects.
•Tax expense for the period increasing by $11m following
higher operating earnings.
Non-GAAP profit measure
1
Contact has recognised a net onerous contract provision expense for AGS of $113m within EBITDAF and $84m within profit. Underlying performance excludes these impacts. All variances and commentary reflect movements in underlying performance.
2
Contact has made reclassifications to better align with IFRIC guidance on IFRS 9 resulting in realisedgains/losses from market derivatives not in a hedge relationship (includes market making activity) no longer being reported in operating income
(EBITDAF). FY22 figures restated accordingly.

44
Historical financial information
UnitFY19FY20FY21FY22
1
FY23
Underlying
2
Reported
Revenue$m2,5192,0732,5732,3872,118
Expenses$m2,0011,6272,0201,8201,5001,613
EBITDAF$m518446553546573460
Profit$m345125187182211127
Operating free cash flow$m341290371330282
Operating free cash flow per sharecps47.540.450.242.436.0
Dividends declared cps3939353535
Total assets$m4,9544,8965,0285,1665,808
Total liabilities$m2,1722,2752,1012,3263,004
Total equity$m2,7822,6212,9272,8402,804
Gearing ratio
3
%2831232836
Historic performance
1
Contact has made reclassifications to better align with IFRIC guidance on IFRS 9 resulting in realisedgains/losses from market derivatives not in a hedge relationship (includes market making
activity) no longer being reported in operating income (EBITDAF). FY22 Expenses, EBITDAF and operating free cash flow are restated accordingly; FY22 operating free cash flow has also been
restated following the reclassification of $4 million of growth capex to SIB capex.
2
Contact has recognised a net onerous contract provision expense for AGS of $113m within EBITDAF and $84m within profit. Underlying performance excludes these impacts.
3
Gearing ratio is calculated as: Senior debt - including finance lease liabilities / (Senior debt - including finance lease liabilities + Equity).

45
FY23FY22
Year ended 30 June 2023Year ended 30 June 2022
VolumeGWAPVolumeGWAP
Note: this table has not been rounded and might not addGWh$/MWh$mGWh$/MWh$m
2

Electricity sales to Retail segment3,727 129 482 3,689 107 395
Electricity sales to C&I (netback)1,499 114 171 1,373 95 130
Electricity sales – Direct to Customer78 159 12 81 134 11
Electricity sales to C&I1,577 116 183 1,454 97 141
CfDs – Tiwai support sales938875
CfDs - Long term sales524470
CfDsand ASX -Short term sales9131,627
Electricity sales – CFDs2,375 94 223 2,972 109 323
Total contracted electricity sales7,678 116 889 8,114 106859
Steam sales587 60 35 595 56 33
Other income4(1)
Net income on gas sales2 3
Net income on electricity related services6 (1)
Net other income121
Total contracted revenue8,265 113 9368,709 103 893
Generation costs
1
7,622 (31)(239)8,350 (34)(283)
Acquired generation cost150 (120)(18)389 (142)(55)
Generation costs (including acquired generation)7,772 (33)(257)8,739 (39)(338)
Spot electricity revenue7,544 82 621 8,269 137 1,129
Settlement on acquired generation150 66 10 389 160 62
Spot revenue and settlement on acquired generation (GWAP)7,694 82 631 8,658 138 1,192
Spot electricity cost(5,226)(93)(488)(5,062)(153)(775)
Settlement on CFDs sold(2,375)(81)(192)(2,972)(140)(415)
Spot purchases and settlement on CFDs sold (LWAP)(7,600)(89)(680)(8,033)(148)(1,190)
Trading, merchant revenue and losses93 (48)625 1
Wholesale EBITDAF underlying
1
632557
Onerous contract provision113
1

Wholesale EBITDAF reported519557
Wholesale segment
Segmental performance
1
Contact has recognised a net onerous contract provision expense for AGS of $113m within EBITDAF and $84m within profit. Underlying performance excludes these impacts.
2
Contact has made reclassifications to better align with IFRIC guidance on IFRS 9 resulting in realisedgains/losses from market derivatives not in a hedge relationship (includes market making activity) no longer being
reported in operating income (EBITDAF). FY22 figures restated accordingly.

46
Residential electricityunit
FY20FY21FY22FY23
Residential gasunit
FY20FY21FY22FY23
Average connections#355,073357,117373,347
380,482
Average connections#61,59160,70164,649
66,605
Sales volumesGWh2,5322,5202,644
2,688
Sales volumesTJ1,5771,4951,583
1,504
Average usageMWh per ICP7.17.17.1
7.1
Average usageGJ per ICP25.624.624.5
22.6
Tariff$/MWh250.4253.4256.4
272.1
Tariff$/GJ33.135.3
36.642.1
Network, meters and levies$/MWh-122.1-118.0-119.5
-122.7
Network, meters and levies
1
$/GJ-18.5-18.6
-18.9-22.9
Energy costs$/MWh-94.8-100.2-115.0
-139
Energy costs$/GJ-7.9-8.6
-11.8-10.1
Gross margin$/MWh33.535.221.9
10.8
Carbon costs$/GJ-1.4-1.5
-2.1-4.2
Gross margin$ per ICP239249155
77
Gross margin$/GJ5.36.5
3.84.9
Gross margin$m858958
29
Gross margin$ per ICP136107
92112
Gross margin$m810
67
SME electricityunit
FY20FY21FY22FY23
SME gasunit
FY20FY21FY22FY23
Average connections#55,03349,67948,45946,962Average connections#3,9493,8763,8893,519
Sales volumesGWh991860798794Sales volumesTJ1,4411,3131,2241,063
Average usageMWh per ICP18.017.316.516.9Average usageGJ per ICP365339315302
Tariff$/MWh229.3231.7239.7259.3Tariff$/GJ15.416.319.825.2
Network, meters and levies$/MWh-115.8-106.4-112.9-117.0Network, meters and levies$/GJ-6.0-7.9-8.3-9.5
Energy costs$/MWh-93-99.3-113.7-138.6Energy costs$/GJ-7.9-8.6-11.8-10.1
Gross margin$/MWh20.526.113.03.6Carbon costs$/GJ-1.4-1.5-2.1-4.2
Gross margin$ per ICP36945121562Gross margin$/GJ0.2-1.6-2.41.4
Gross margin$m2022103Gross margin$ per ICP63-552-769412
Gross margin$m0-2-3
1
Broadband
unit
FY20FY21FY22FY23
Retail segment EBITDAF
FY20FY21FY22FY23
Average connections#19,97939,24562,38879,057Electricity Gross margin$m1051116832
Tariff$/cust/mth70.168.270.169.6Gas Gross Margin$m9839
Network, provisioning, modems$/cust/mth-69.6-69.9-60.5-63.5Broadband Gross Margin$m0-176
Gross margin$/cust/mth0.5-1.69.66.17Total Gross Margin$m1141187947
Gross margin$m0.1-176Other income$m5679
Other operating costs$m-69-68-68-69
Retail segment EBITDAF$m505517-14
Corporate allocation (50%)$m-15-15-14-22
Retail EBITDAF$m35403-36
EBITDAF margins (% of revenue)%3.6%4.3%0.3%-3.3%
Retail segment
Historic performance
1
FY22 Retail residential and SME gas network costs split was re-stated to align to the latest data

---

Results announcement





Results for announcement to the market
Name of issuer Contact Energy Limited
Reporting Period 12 months to 30 June 2023
Previous Reporting Period 12 months to 30 June 2022
Currency NZD
Amount (000s) Percentage change
Revenue from continuing
operations
$2,118,000 -11.3%
Total Revenue $2,118,000 -11.3%
Net profit/(loss) from
continuing operations
$127,000 -30.5%
Total net profit/(loss) $127,000 -30.5%
Interim/Final Dividend
Amount per Quoted Equity
Security
$0.21000000
Imputed amount per Quoted
Equity Security
$0.07000000
Record Date 08/09/2023
Dividend Payment Date 26/09/2023
Current period Prior comparable period
Net tangible assets per
Quoted Equity Security
$3.00 $3.07
A brief explanation of any of
the figures above necessary
to enable the figures to be
understood

Authority for this announcement
Name of person

authorised
to make this announcement
Kirsten Clayton, General Counsel & Company Secretary
Contact person for this
announcement
Shelley Hollingsworth, Investor Relations & Strategy Manager
Contact phone number +64 27 227 2429
Contact email address shelley.hollingsworth@contactenergy.co.nz
Date of release through MAP

14/08/2023

Audited financial statements accompany this announcement.

---

Distribution Notice




Section 1: Issuer information
Name of issuer Contact Energy Limited
Financial product name/description Ordinary shares
NZX ticker code CEN
ISIN (If unknown, check on NZX
website)
NZCENE0001S6
Type of distribution
(Please mark with an X in the
relevant box/es)
Full Year X Quarterly
Half Year Special
DRP applies X
Record date 08/09/2023
Ex-Date (one business day before the
Record Date)
07/09/2023
Payment date (and allotment date for
DRP)
26/09/2023
Total monies associated with the
distribution
$164,842,325
(784,963,454 shares @ $0.21 / share)
Source of distribution (for example,
retained earnings)
Operating Free Cash Flow
Currency NZD
Section 2: Distribution amounts per financial product
Gross distribution $0.28000000
Gross taxable amount $0.28000000
Total cash distribution $0.21000000
Excluded amount (applicable to listed
PIEs)
N/A
Supplementary distribution amount $0.03176471
Section 3: Imputation credits and Resident Withholding Tax
Is the distribution imputed

Fully imputed
Partial imputation
No imputation
If fully or partially imputed, please
state imputation rate as % applied
25%
Imputation tax credits per financial
product
$0.07000000
Resident Withholding Tax per
financial product
$0.02240000
Section 4: Distribution re-investment plan (if applicable)
DRP % discount (if any)
0% - No discount

Start date and end date for
determining market price for DRP
07/09/2023 13/09/2023
Date strike price to be announced (if
not available at this time)
15/09/2023
Specify source of financial products to
be issued under DRP programme
(new issue or to be bought on market)
New issue
DRP strike price per financial product
Not available at this time
Last date to submit a participation
notice for this distribution in
accordance with DRP participation
terms
11/09/2023
Section 5: Authority for this announcement
Name of person

authorised to make
this announcement
Kirsten Clayton, General Counsel & Company Secretary
Contact person for this
announcement
Shelley Hollingsworth, Investor Relations & Strategy
Manager
Contact phone number +64 27 227 2429
Contact email address shelley.hollingsworth@contactenergy.co.nz
Date of release through MAP

14/08/2023

---

2023 Integrated Report
Investment.
Transformation.
Decarbonisation.

About this Report
Welcome to our Integrated Report 2023; our annual document
that explains how we create value over time and how we’re
implementing our strategy to lead the decarbonisation of this
special place we call home, Aotearoa New Zealand.
This has been a year of real progress, marked by key significant achievements.
Our leadership team has reviewed this report, and our CEO Mike Fuge together
with the Board confirms that this is a true and accurate picture of the way Contact
has created value for shareholders over the past year to 30 June 2023.
We’re proud to share our story and hope that you find it enlightening. For our
people, our customers, investors, local communities, tangata whenua, suppliers,
business partners, regulators, policymakers and lawmakers, this is for you.
This document follows the principles of the Integrated Reporting Framework and
reflects our ongoing quest towards integrated thinking focused on value creation.
It is structured around the Contact26 strategy. It uses the Global Reporting
Initiative (GRI) standards and the International Integrated Reporting Council <IR>
Framework to report on material ESG activities and provide a balanced view of
performance.
This report is dated 14 August 2023 and signed on behalf of the Board of Directors
of Contact Energy.
2023 Integrated Report
Investment.
Transformation.
Decarbonisation.
Our Chair Robert McDonald and our
directors will host shareholders at the
Contact Energy AGM in November 2023.
Shareholders will be given notice of the
meeting and agenda in October 2023.
We are listed on both the NZX and ASX.
Sandra Dodds
Chair, Audit and Risk Committee
Robert McDonald
Chair
Most Contact Energy shareholders receive digital
reports. However, we have printed 1,500 reports
using environmentally responsible paper and inks.