UBS Australasia Conference Presentation

1
1
UBS Australasia
Conference
November 2022

22
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 of 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
reflectspublic announcements of intention only.

33
Presenters
Dorian Devers
Chief Financial Officer
Dorian joined Contact in December 2018 as Contact’s Chief Financial Officer.
Dorian is experienced in business transformations having led successful turnarounds of businesses in both the UK and South
Africa. He has successfully delivered several acquisitions including ones in the Australian and New Zealand energy sector. Hehas
governance experience having served on the Board of Afrox a publicly listed company and the largest industrial gases businessin
Africa, as well as being a previous Board member of Liquigasa New Zealand LPG infrastructure business.
Mike Fuge
Chief Executive Officer
Mike Fuge was appointed CEO in September 2019 and joined Contact in February 2020.
Mike was previously the chief executive of Refining New Zealand and has a long history in the energy sector, both in New
Zealand and internationally. He has previously been the chief executive of global renewable energy owner operator and
developer Pacific Hydro in Australia and held senior roles at Genesis Energy and Royal Dutch Shell Group.
3

44
<IR>
ESG CREDENTIALS
The investment opportunity in our core market is largeand in line with our unique capability which will deliver cash
flow growth ultimately flowing through to dividends
Resilient generation portfolio: Strong cash flow
generation and operational performance with
best-in-class commodity risk management
Strong balance sheet to support growth investment;
with clear distribution policy to reward shareholders
Shares offer relative value and liquidity when
benchmarked against peers
Unique geothermal expertise
Inflationary cost pressures recoverable
Committed to decarbonising
our generation portfolio and
New Zealand
Why invest in Contact?
Delivering for
shareholders
World class geothermal resources being developed, committed to deliver 1.9TWh
p.a. of renewable baseload by end of 2024

55
Sources: New Zealand's Greenhouse Gas Inventory 1990-2020 snapshot, 2022 Inventory, TeRārangi
HaurehuKati Mahanaa Aotearoa 1990-2020 -He whakarāpopotoNew Zealand
Meaningful reductions in carbon emissions are possible with renewable
electricity displacing carbon intensive fuels
With New Zealand's high renewable penetration, electricity is the solution to reducing carbon emissions, not
the problem
Paris agreement target, Mt CO2e
(Transpower, 2020)
52
16
17
21
Net zero
2050
Gross
emissions
ex biogenic
methane
2
Net
growth
Other
abatement
required
Electri-
fication
Forestry
carbon
capture
0
Electrification will reduce carbon emissions
Our future energy profile
(Climate Change Commission, 2021)
29
35**
Renewable
electricity as % of
total energy use
2
Source: Climate change commission 2021 final advice
2
Based on Consumer Energy use rather than Primary Energy use
Greenhouse gas emissions by sector
(Greenhouse Gas Inventory, 2020)
2022
2035
Total
electricity
(TWh)
41
51
To meet this annual emissions reduction,
Transpowerestimates 70% more renewable
generation is required to electrify heat and
decarbonisetransportation. This amounts to
~23TWh p.a.
This is the equivalent investment
of around $690m every year for
27.5 years
1
2050
Source: WhakamanaiTeMauri Hiko-Empowering our Energy Future,
March 2020 (Transpower)
1
Based on the cost of the Meridian Harapakiwind farm as per August
2022 NZX announcement ($448m, 542GWh p.a.)
**Transpowerand Climate Change Commission
analysis preceded the Government’s first
Emissions Reduction Plan: Targeting an even
more ambitious trajectory with renewables at
50% of total energy consumption by 2035
58-75
>50

66
The New Zealand regulatory framework is being adapted to deliver on this societal imperative. There is political consensus to
deliver net zero by 2050 and on the emissions reductions budgets needed to get there
Society is demanding action on climate change, with clear progress expected.
¹ While the government’s first Emissions Reduction Plan has now been released, there is ongoing work on implementation and furtherplanning
2
Coveringelectricity, hydrogen, and industry decarbonization. Terms of Reference have been released
3
Government is consulting on recommendations by the Climate Change Commission on the unit limit and price control settings of the ETS
4
Including BCG’s “The Future is Electric”; EA/Transpower’s“Future Security and Resilience Project”; EA’s Market Development Advisory Group; Wholesale Market Review (EA currently consulting on proposals)
Government
Energy
Strategy
2
Current
Tiwai
contract
ends 2024
Gas
Transition
Plan
Transport
policies
Net zero
New
Zealand
carbon
emissions
by 2050
Government
Procurement
Market
reviews to
support
highly
renewable
market
4
Significant
increase in
GIDI
subsidies
Resource
consenting
reform
Transmission
pricing and
grid
upgrades
Emissions
Reduction
Plan
1
Emission
Trading
Scheme
review
3
Potential electricity demand impactPotential renewable generation impactPotential wider electricity sector impact
In progress
Announced
New
Zealand
Battery
Project
feasibility
Climate change and regulation

7
7
Government support for decarbonisation
The Government has recently released its first Emissions Reduction Plan in response to the Climate Change
Commission recommendations
An economy-wide plan to meet New Zealand’s net zero emissions target by 2050. It includes specific actions government will undertake, as well as policies and strategies to influence
emissions from private firms. There are three key impacts for Contact Energy:
1. Target of reaching 50%
total energy consumption
from renewable sources
by 2035
Government developing an ‘Energy
Strategy’ by the end of 2024
Strategy will include an action plan
for decarbonising industry
Strategy will also consider how to
make it easier to gain consents for
renewable generation
2. A large boost in financial support for decarbonisation3. New Zealand carbon prices expected to
continue to rise, further incentivising switching
Carbon priced at $85per unit at September2022 auction. Price
is expected to rise as number of auctioned credits reduces
which is creating demand for increased electrification
Government has allocated a further $200m+ to decarbonise the public
sector, focussing on replacing coal boilers
Government has committed $650m+ over the next four years to
contribute to the costs of industry decarbonisation projects
$27.8m
$28.0m
$13.0m
$69.6m
$151.4m
$207.4m
$223.8m
$68.7m funded to date
$652.2m allocated
2019/202020/212021/222022/232023/242024/252025/26
GIDI¹ Fund commitment
Carbon Price Trajectory: Estimate of the carbon
price required to achieve net zero target
New Zealand Climate Change Commission, 2021
¹ GIDI: Government Investment in DecarbonisingIndustry
0
50
100
150
200
250
300
2020202520302035204020452050
$ per tonne CO
2
e (real 2019 NZD)
CCC’s 2022 cost
containment
recommendation
2
2
In July 2022 the Commission recommended a step-up in the ETS cost
containment trigger price: $171 in 2023; $214 in 2027
EU CP

8
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

9
9
Positive outlook for demand
New data centre build
Data centres proposed by the following companies
Data centres looking to enter New Zeland, and energy intensive industries looking to sign up long-term renewable energy
agreements
Several credible data centre owners have publicly announced they
are planning to invest in New Zealand
The baseload characteristics of data centres make them attractive
Hyperscale
data centres
Edge data
centres
20222024
2023
DataGrid
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 reflectspublic announcements of intention only.
Tiwai smelter (NZAS) extension beyond 2024 appears likely:
•Aluminium economics materially improved
•Rio Tinto carbon reduction targets aligned with extension
of the renewably powered NZAS smelter, without
significant renewable energy investment
•Reduced international aluminium smelting capacity
•Strong long-term demand outlook for aluminium
A
B
C
•Transpower competed the Clutha Waitaki
Lines Project in April 2022, allowing an
additional 400 MW of electricity to flow north
Three major electricity users signed to long-term Tauhara
backed electricity signed (PPA). Genesis contract
beginning 2025 and the other two in April 2024:
15 MW / 10 years
10 MW / 10 years
62.5 MW / 15 years
Energy intensive industries
2,470
2,826
3,949
NZAS notice of
termination (Jul 20)
NZAS extension
(Jan 21)
+1,123
(+40%)
Al (US$)Al (NZ$)
Aluminium price
(/tonne)
Current
(Nov-22)
Electric vehicle uptake
Increasing uptake of EVs: 16% of all registrations in August 2022
1
¹ Ministry of Transport

10
10
Baseload thermal substitution
Despite higher expected long run electricity prices, the economics of baseload
thermal generation remains challenged with fuel costs expected to continue to
remain above estimated long run, renewable backed PPA pricing¹. The break
even gas cost reduces as carbon costs rise (as expected)
39
37
41
65
68
81
76
77
83
81
Jan-21Jan-22Apr-21Jul-21Oct-21Apr-22Jul-22Oct-22
50
NZ carbon price ($/unit)
11
18
38
63
74
102
67
42
120
Carbon
Carbon at $85/unit2020
Gas
2021Carbon at $140/unit
85
105105
$8.9/GJ
2022 real
Thermal fuel costs at average market prices
This issue is more acute when fixed operating costs and return on capital requirements are
considered
Rising carbon costs
(+124% on Jan 2021) are
at thermal / electricity switching
points for new
boiler investments if electricity
supplied long-term through Power
Purchase Agreements (PPA)
Current
carbon price
CCC 2030
estimate
$5.6/GJ
2022 real
$/MWh
Average market prices
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.
Economic switching
range
Equivalent gas
prices implied
by long-run price
expectation
Process heat conversion and baseload thermal substitution
Positive outlook for demand
Process heat conversion
Since 2020, there has been $69m in confirmed GIDI funding for process heat conversion
projects
The Government has allocated an additional $650m over four years, with a commitment to
allocate a further $330m for industrial decarbonization post 2026/27
Application of funding will drive conversions to new electric boilers (~50MW). These
projects are expected online by April 2024
Each for
13MW
boilers
¹ Ultimate pricing for renewable PPAs will include consideration of the offtake credit rating and credit support, the location of
take, firming commitments and outage cover and term.

11
11
Market leading development pipeline
1.4
Current generation (p.a.)
0.2
0.3
Te Huka 3
(under construction)
Potential generation
under current consents
2.8
0.3
GeoFutures
(net of Wairakei retirement*)
Tauhara
(under construction)
0.4
1.41.1
0.7
Tauhara (remaining)
2.83.1
3.3
0.4
6.2
+3.0
Geothermal generation potential (TWhp.a.)
Geothermal field responses to extraction and
injection will determine the ultimate geothermal
generation potential beyond current consents.
Wairakei field
Tauhara field
Ohaakifield
*Expected enthalpy decline at Wairakei is expected to be offset through continuous improvement projects
2021
Potential geothermal development projects
2025
Tauhara
(174MW)
Investment
approved
Under
construction
TeHuka
(51.4MW)
Investment
approved
Under
construction
GeoFutures
(168MW)
Development
option currently
being assessed
Potential generation
impact
2022202320242026
>2027
Tauhara
Tauhara
stage 2
(90MW)
Remaining
capacity
TeHuka
GeoFutures
All uncommitted investment /
closures are subject to Board
investment decisions
Wairakei
closure
(115MW)
Net addition
In line with core markets and capability

12
12
Strategic acquisitions and partnerships
to build capability
Solar: LightsourceBP partnership adds solar development capability
Wind: Roaring40s adds wind development capability
Capability and resourcing to accelerate Contact’s position in grid-scale solar
Immediate access to world-leading solar development. Strong connections
into solar supply chains and dedicated procurement functions to source solar
components for LSBP’s projects around the globe
Extensive experience, legal documentation and processes for establishing
special purpose vehicles (SPV) and undertaking project financing activities
Likely will provide on-going operations and maintenance (O&M) services to
any developed solar farms
Creditworthy counterparty to support a Power Purchase Agreement (PPA)
which is a major hurdle to securing project finance and de-risking a project
Significant experience in the New Zealand electricity market for both trading
and development, providing assurances to LSBP on risks associated with
entering a new market
Strong stakeholder relationships
Immediate wind development
experience having been involved in
~70% New Zealand wind projects
Deep knowledge of New Zealand’s
undeveloped wind sites, giving us a
head start
Strong balance sheet to support build
of renewable generation
Ability to incorporate and trade wind
developments into market
Strong consenting and community
relationships
Assessment and consenting of low-cost wind sites
in an exclusive partnership until April 2026
Exclusive partnership to deliver series of grid-scale solar generation projects initially targeting 250MWp by 2026
Status of wind under development
»Commenced consenting of priority South Island site
»Land access secured for a further 450MW of wind
development potential
Status of solar under development
»Commenced consenting of priority North Island site
»Land access secured for a further 55MWp of solar development potential
55
185
240
MWp
450
220
Land access securedConsenting underway
670
MW
»Contact only includes indications of capacity that are sufficiently progressed (land access secured at a minimum)
»Advanced land access negotiations are under way for additional wind and solar sites

13
13
Decarbonising our portfolio: Leading an
orderly transition to renewables
Key outcomes:
•Act on our commitment to ESG, contributing to better outcomes for our communities and the
environment
•Support secure 24x7 electricity supply for Contact’s customers and all other market
participants
•Capture the value flexibility offers to the electricity market
•Provide an integrated system to support the transition to renewables by providing risk-
coverage to the market and reducing price volatility
•Reduce fixed costs by finding cost reductions, synergies and highest-value ownership
Other external commitments
Our targets have been approved by the Science-based targets
initiative (1.5 degreewarming)
Reduce Scope 1 and 2 GHG emissions 45% compared to 2018
baseline by 2026
30% reduction of 2018 Scope 3 GHG emissions by 2026
2021
2022
2023
2012 emissions
450
FY21
1,046
Closure of
Te Rapa
200
Closure of TCC
106
Geothermal
additions
37
2025 emissionsReduced
Thermal
Peaker
generation
465
648
SBTI target
2026
Thermal review announced
ThermalCodiscussion paper released
Closure of TeRapa announced
Risk management product sold to Meridian
Geothermal carbon reinjection trial on track
TCC closure once operating hours end (est2024)
Complete review of thermal assets
Scope 1 & 2 GHG emissions (ktCO
2
e)
2,698
1
1
Contact’s annual emissions return to the Environmental Protection Authority for calendar year 2012. Reflects scope 1 emissions ex diesel

14
14
Aluminium
Demand
Short-term external factors that
can influence the market
Changes as at end October 2022
in comparison to Jan 2021
Source: ASX
Short-term
wholesale
electricity
prices
There is currently extreme volatility across commodity markets, driven by a combination of global energy supply and security concerns, exacerbated by the impact of theRussian invasion of Ukraine, with subsequent
unprecedented increases in international energy prices including coal, gas and oil. Domestically, gas field outages and highcoal and gas prices have contributed to a steep escalation in wholesale electricity prices.
Gas available for
thermal generation –
Contact expected
delivery from
Pohokuraand Maui
contracts over the next
12 months down by
24% vs.6 months ago
Carbon prices up
124% to $85/New
Zealand Unit
Methanol pricing
at US$361/t
(up 4%)
Demand in line with expectation
Aluminium prices higher
(+$1,123/t, up 40%).
Increase in coal prices
+US$300/t (375%)
Wholesale risks remain elevated
Volatile hydro storage in last
6 months. Controlled
storage at ~140% of mean
(900GWh above mean) in
October.Was at ~80% of
mean (500GWh below
mean) in June
Forward wholesale pricing reflects current market conditions, includingfuel cost and availability risks
300
50
100
150
200
250
Q3
24
Q4
2022
Q4
24
Q1
23
Q4
23
Q2
23
Q3
23
Q1
24
Q2
24
Q2
26
Q1
25
Q4
25
Q2
25
Q3
25
Q1
26
Q3
26
Q4
26
Elevated wholesale pricing out to 2026
ASX Futures (Quarterly, base period)
$/MWh
Wholesale market conditions are volatile:
»Q4 2022 impacted by high hydro storage following 95
th
percentile hydro inflows in Q3 2022
»Winter 2023 impacted by lower expected gas availability, high coal and carbon costs and the
end of the ‘swaption’ contracts
»Wholesale prices reduce as new renewable generation is brought online despite the expected
closure of thermal generation capacity
2023 average
$207/MWh
2024 average
$193/MWh
2025 average
$179/MWh
2026 average
$178/MWh

15
Long-term pricing is linked to the long-run marginal costs (LRMC) of new renewable projects to meet
demand plus costs associated with firming renewable intermittency
Long run pricing expected to revert to $100 –
$110/MWh from $85/MWh previously
Previous (~2019/20)Current (2022)
Capex
$m/MW
Sector
WACC
1
LRMC
2
($/MWh)
Capex
$m/MW
Sector
WACC
1
LRMC
2
($/MWh)
Geothermal
3
4.46.5%$55 to $655.87.5%$70 to $80
Wind
4
2.26.5%$65 to $752.77.5%$85 to $95
Solar
5
Project capex up ~20% driven by higher commodity and shipping costs
HydroNot considered due to environmental limitations of new hydro development
1
Weighted Average Cost of Capital taken from broker ranges across MCY, MEL, GEN and CEN at ~6-7% in 2019/20 and
~7-8% in 2022
2
LRMC = Long run marginal cost of new renewable generation (before firming). Electricity price (real) to deliver NPV = 0
3
Announced capital costs of Tauhara (early 2021) and TeHuka(2022)
4
Announced capital costs on Turitea(2019) and KaiweraDowns (2022)
5
International Energy Agency; Analyst estimates
Variable costs($/MWh)
Variable
costs($/MWh)
Fixed cost pa
(100MW)
Gas
6
$120 to $140$200 to $220$30-35m
Coal
7
$150 to $200$400 to $450$13m
Biomass
Indicative assessment: At current carbon and fuel pricing, biomass appears
competitive to coal
8
Contact’s current view of long-run wholesale price $100-110/MWh
Historic view of long run wholesale price $80-90/MWh
Indicatve
LRMC (pre
-
firming)
Cost of firming
6
Based on heat rate and carbon intensity of Peaking plant; Capacity cost includes storage, operating costs and return on capital
7
Applies the Genesis MSO calculation in both periods (2019 being an illustration of the current MSO structure
on 2019 underlying pricing)
8
Genesis Energy Insights on Biofuels (Presentation, May 2022)
9
Differences between 2022 and 2019 averages in NZD
Inflationary conditions
(over last 3 years)
Current broker views $85-115/MWh (average $98/MWh)
»Capacity factors of solar, wind and geothermal are around 20%, 40% and 95%
respectively in New Zealand
»Any renewables being built therefore require firming. This firming can come from thermal
generation, batteries, demand response or overbuilding of renewables, but comes at a
cost
Coal
+376%
9
Gas
+40%
9
Variable
costs of
coal-
backed
firming
+140%
Variable
costs of
gas-
backed
firming
+60%
New
renewables
capex
+20-30%
Industry
funding
costs
+15%
New
renewables
LRMCs
+20-30%
(pre -
firming)
Carbon
+213%
9

16
16
Schedule
Cost
Resource / capacity
Project returns remain strong. Key
drivers have moved favourably
since FID:
✓Overall capacity increase of
14%
✓Higher electricity futures pricing
from contracted Tauhara
generation indicated by futures
prices
✓Longer term wholesale price
expectations have increased,
reflecting higher costs of
developing and firming new
generation
Translating to:
✓Higher recovery through
inflation linkages on PPA or
market pricing
Tauhara will deliver more
renewable generation than
originally expected
Expected project costs of $880m¹. This is $62m higher than previously
expected, equating to an increase of 4% on a $/MW basis
Cost increase of $202m since final investment decision (FID):
1.27% increase for marginal capacity expansion of power station, drilling
and the steam field to deliver higher output
2.39% of increase due to scope definition of the separation plant and plant
complexity both being beyond expectations
3.34% of increase associated with COVID
Estimated sources of cost increase
7%
5%
39%
Contingency
27%
10%
Commodity
prices
NZ construction
Capacity
increase
De-risk schedule
Scope definition maturity & complexity
12%
On track for first steam supplied
to power station in Q2 of
calendar 2023
Have stepped up mitigations to
de-risk the schedule
»Established project
acceleration office
»Enhanced monitoring and
performance practices
»Scaled up project team
expertise and capacity for
managing interface with
contractors
¹ Total estimated construction costs related to this phase of development (2008 –2024). Excludes capitalised interest. This will be reduced by up to $20m of commissioning revenue which reduces capital costs
Targeting 4Q of calendar
year 2023 for station on-
stream date
Capital cost up reflecting capacity addition, inflationary environment and initiatives to de-risk the schedule
Tauhara capacity further increased
Returns
Tauhara station capacity upgrade
The additional capacity
wasachieved at an
incrementalcapital cost of
~$2.5m/MW (thisis 51%
below the all-in capitalcost)
$202m
152
168
174
Feb-21Feb-22Nov-22
+22
1.26
1.40
1.45
TWhpa
Confidence on cost forecast driven by all aspects of design complete, 90% of
go forward costs contracted, a contingency of 13% on go-forward non EPC
capex, and expecting ~$20m of commissioning revenue to be capitalised
which provides a further contingency
MW

17
17
Contact indicative EBITDAF after completion of
announced investment programme
480480
520
550
720
40
88
57
41
Thermal fuel
substitution²
FY21
guidance
Normalised
EBITDAF
uplift
FY20
guidance
FY23
guidance
1
Normalised
EBITDAF
uplift
FY22
guidance
30
Tauhara-back
long-term
agreements³
15
Merchant
strip
4
Net operating
costs
5
Cal year 2025Potential re-
pricing
opportunity
of long-term
channels, net
of operating
cost inflation
1.825 TWhp.a. of new base load geothermal from
Tauhara and TeHuka expected to be generating by
2025
¹ See slide 28 of FY22 results presentation for assumptions underpinning FY23 normalisedand expected earnings
² Substitution of around 875GWh of thermal generation from TCC and TeRapa at the expected FY23 fuel cost of $115/MWh less net revenue from Fonterra linked to TeRapa (steam and electricity sales)
³ Expected revenue from long-term PPA electricity sales already signed
4
Additional sales above the FY23 contracted position (250GWh) at the 2025 ASX average price of $162/MWh (as at 11 August 2022). Estimate not revised for current ASX pricing (2025 average of
$179/MWh) or the extra 50GWh p.a. of generation now expected from Tauhara
5
Geothermal operating costs for new stations net of reduction in operating costs following the closure of thermal assets
Long-term channel
netbacks remain
below wholesale
market expectations
788T
of C02e
~450T
of C02e
Scope 1 and 2 emissions
Growth investmentDriven by pricing and channel management
922T
of C02e
446
553
537
Actual
Normalisedand expected EBITDAF ($ million)
1,046T
of C02e

1818
Appendix

19
57
43
50
48
70
942
852
-258
-252
-258
-265
-304
-51
-46
-76
-85
-80
-184
-152
-230
-185
-168
FY22FY23
normalised
and
expected
FY19
1,023
FY20FY21
1,068
1,031
Electricity
sales revenue
537
Other gross
margin
Fixed operating
costs
550
Location losses
Variable
fuel costs
505
446
553
Operating earnings (EBITDAF)
103
105
108
106
110
3.70
0.81
3.79
FY19
3.61
1.33
3.74
FY20
0.83
FY21
3.69
1.39
FY22
1.45
FY23*
4.94
4.59
4.57
5.08
5.15
RetailLong-term sales
84
83
101
117
122
1.13
1.67
1.44
0.25
1.50
0.63
FY19
0.34
FY20
2.14
FY22
0.55
1.77
FY21
0.39
1.05
2.23
FY23*
1.52
1.30
ThermalAcquired
Electricity sales
Variable fuel costs
11111
4.23
6.81
3.26
FY19
3.75
3.33
FY20
3.11
3.70
FY21
3.94
3.28
FY22
3.90
3.25
FY23*
7.49
7.08
7.22
7.15
HydroGeothermal
(i) Renewables
(ii) Thermal and acquired
93
87
131
133
141
3.02
0.86
1.04
2.10
0.93
2.17
FY19FY20
0.97
1.26
1.23
0.50
0.94
1.94
FY21
0.63
FY22
5.03
1.20
1.60
3.30
FY23*
4.29
4.10
3.66
Commercial and IndustrialSpot salesCFDs
(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 ($m)
1
EBITDAF
5
1
5
*FY23 normalised and expected provides an indication of the expected FY23 performance from Contact in a mean hydrological year. If hydro inflows are below mean, then more thermal generation will be required to support the fixed sales position
increasing costs and reducing operating earnings in line with the thermal and acquired fuel cost. There remans price risk in forward projections. See slide 28 of FY22 results presentation for details around the contractual sales position
Actual Forecast
Actual Forecast
98
96
118
117
122
9.04
9.62
8.868.74
8.45
Price ($/MWh)
Volume (TWh)
Electricity revenue: Electricity sales (net of network,
meters costs) for all sales channels
•Pricing: Long-term channels linked to inflation, market
channels are linked to futures pricing
•Volumes: Variable, dependant on hydrology and fuel
Other gross margin: Steam sales revenue, retail gas
gross margin, broadband gross margin and other
income
•Growing broadband contribution offsetting gas retail
margin decline
Fixed operating costs: Electricity and gas
transmission, gas storage costs and other operating
costs (includes labour, maintenance expenses, cost
to serve, cost to acquire and development)
•Inflation linked
Location losses: Difference between wholesale
revenue from generation assets and costs to
purchase electricity to support sales
•Expected to approximate ~6 to 7% of electricity sales
revenue
Variable fuel costs: Gas, carbon and acquired
generation to manage risk
•Cost: Thermal generation costs continue to rise on
higher gas and carbon costs
•Volumes: Variable, dependant on hydrology and
wholesale prices vs fuel costs
1
3
4
5
2
Annual sensitivities
2
3
4