Contact’s performance reflects short term market conditions
contactenergy.co.nz
NZX release: 13 February 2023: Contact Energy 1H23 Result
Contact’s performance reflects short-term wholesale market
conditions, investing in decarbonisation strategy
Key financial metrics
Six months ended
31 December 2022
1H23
Six months ended
31 December 2021
1H22
Underlying
1
Reported Against underlying
EBITDAF
2
$246m $126m ↓ 24% from $322m
Profit $79m
($7m) ↓ 41% from $134m
Profit per share 10.1 cps
($0.9) cps ↓ 41% from 17.2 cps
Operating free cash flow
3
$60m ↓ 54% from $131m
Stay-in-business capital expenditure $55m ↑ 57% from $35m
Growth capital expenditure (cash) $217m ↑ 87% from $116m
Overview
New Zealand renewable energy company Contact Energy (‘Contact’) today released its
interim financial results for the six months to 31 December 2022.
Contact CEO Mike Fuge said the financial performance in the first half of the FY23 financial
year was reflective of soft short-term wholesale market conditions. Contact had made strong
progress on delivering to its Contact26 strategy and was focused on leading New Zealand’s
decarbonisation by connecting customers with its renewable development pipeline.
• Net loss of $7m reported after recognising an onerous contract provision of $120m
($86m after tax) following a review of the estimated available capacity of the Ahuroa
Gas Storage Facility (AGS). Excluding AGS, underlying net profit was $79m.
• Underling EBITDAF (pre-AGS provision) decreased by $76m to $246m as a result of
lower wholesale prices, lower renewable and thermal generation, increased
operating costs to deliver on strategic growth priorities and inflationary conditions.
• Operating free cash flow decreased by $71m to $60m. Working capital continues to
be elevated, with more gas and carbon in inventory.
• Resource consent gained to continue operating on the Wairākei geothermal field for
the next 35 years, enabling planning to proceed on GeoFuture, a new station of up to
180MW at Te Mihi to replace Contact’s 64 year-old operations (Wairākei, 127MW).
1
Underlying EBITDAF and profit are shown excluding a $120 million onerous contract provision ($86 million after tax) for AGS. All variances are
shown on an underlying basis.
2
Refer to slide 36 of the 2023 interim 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).
3
Refer to note A3 of the 2023 interim 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
• Selected by Christchurch Airport to deliver 170MWp (150MW) solar farm at Kōwhai
Park through Contact’s joint venture with Lightsource bp.
• Market leading development pipeline expected to deliver up to 6TWh of new
renewable electricity this decade, with 3.0TWh already consented.
• Te Rapa power station prepared for closure in June. On track to more than halve
FY21 scope 1 and 2 carbon emissions by 2026.
• Strong endorsement of Contact’s refreshed retail offering in the past six months, with
more than 20,000 new connections.
- Expanded ‘time of use’ offerings by introducing Dream Charge, enabling
customers to charge their EVs at home at cheaper night rates and contributing to
the decarbonisation of New Zealand.
- Supported customers by keeping price increases below inflation, despite
sustained higher wholesale prices over the last 3 years.
• Launched a leading parental leave policy, ‘Growing your Whānau’, one of the most
comprehensive, far-reaching parental leave policies in New Zealand.
_________________________________________________________________________
Financial performance
Contact reported a net loss of $7m after recognising an onerous contract provision of $120m
($86m after tax) 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 received and the contracted schedule of payments. Underlying net profit of $79m
was down $55m from a year ago on lower operating earnings (EBITDAF) and unfavourable
movements to the fair value of financial instruments, partially offset by lower depreciation
and lower tax on earnings against the prior year.
Underlying EBITDAF (pre-AGS provision) decreased by $76m to $246m, down 24 percent
on the record result of 1H22, with lower wholesale prices, lower renewable and thermal
generation and increased operating costs to deliver on strategic growth priorities and
reflecting inflationary conditions.
Operating free cash flow for the period decreased from $131m to $60m, down 54% year-on-
year on lower operating earnings, higher stay-in-business capital expenditure and higher
cash tax paid on strong earnings in prior periods. This was partially offset by favourable
working capital movements on a net basis. While lower than last year, working capital was
still elevated as we held more gas and carbon in inventory.
The Board approved an interim dividend of 14 cents per share (imputed by up to 12 cents
per share for qualifying shareholders) to be paid on 30 March 2023.
“Contact’s financial performance reflected the soft short-term wholesale market conditions
experienced in the half year,” said Mr Fuge.
“We saw unprecedented hydro inflows which depressed market prices and saw greater price
separation between the North and South Islands. We responded running less thermal
contactenergy.co.nz
generation and positioned our portfolio to benefit from expected improved market conditions
in the second half.”
“Global energy and supply concerns continued to impact on commodity markets, with
international energy prices holding at unprecedented levels, including coal. Domestic gas
output remains constrained and readily accessible storage has reduced. These thermal fuel
challenges continue to support the acceleration of our Contact26 strategy.”
Demand
In line with Contact’s decarbonisation focus, Mr Fuge said demand for renewable electricity
from forward-thinking customers remained strong. Contact is focused on five key areas for
demand growth, being large scale 24/7 data centres, industrial process heat, major industrial
energy users, road transport and green chemicals.
“While still early days, we are excited about opportunities to work with major energy users
pursuing their own decarbonisation strategies. Examples include working with NZ Steel to
look at options around interruptibility and with the HW Richardson Group to assess a trial
use of hydrogen for heavy transport. These have the potential to lead to large scale sources
of new demand,” Mr Fuge said.
“With all new supply contracts, we are looking to build in demand response. This is of high
value to Contact, our industrial customers and ultimately New Zealand. These initiatives will
contribute to the decarbonisation of New Zealand whilst improving the security of supply at
peak periods. We have been positively surprised by the customer appetite - from retail
customers to large industrials - for demand response mechanisms to be packaged into new
contracts,” said Mr Fuge.
“Significant new electricity demand is also now emerging in New Zealand, with new large
scale 24/7 data centres. Hyperscale data centre projects announced by the likes of CDC,
Microsoft and DCI are starting to come online and will see significant contributions to
electricity demand over the next few years as each project stage reaches completion.”
Rio Tinto is looking to continue operating its unique low carbon smelter at Tiwai Point
beyond 2024. Contact is engaging constructively and working toward new commercial
arrangements.
Renewable development
Contact has been granted new consents to operate on the Wairākei geothermal field for the
next 35 years. This enables it to proceed with replacing the 1950s-built Wairākei A and B
power stations with a new station of up to 180MW at Te Mihi – the GeoFuture project.
Contact is targeting a final investment decision around the end of this calendar year.
“This is an exciting milestone for Contact, moving our geothermal production off-river, and
delivering better environmental outcomes,” said Mr Fuge.
“GeoFuture will be the third major development in five years from Contact’s world-class
geothermal development pipeline, with Tauhara and Te Huka Unit 3 well on track for
completion in 2023 and 2024 respectively. This is all low carbon, baseload renewable
electricity that operates around the clock and is not weather reliant.”
Our joint venture partnership with global solar developer Lightsource bp has been selected
by Christchurch Airport to deliver the first stage of its renewable energy precinct, Kōwhai
contactenergy.co.nz
Park – an estimated 170MWp solar farm. Subject to a final investment decision, construction
is expected to begin in 2024.
Consenting for another 170MWp solar farm in the North Island is underway and the
partnership has land access rights to potentially develop another ~60MWp of solar power.
Decarbonising our portfolio
Contact has announced the successful completion of carbon capture trials at its Te Huka
geothermal power station. This gives Contact the option of either reinjecting carbon back
into the geothermal reservoir, now a routine part of its Te Huka operation, or harvesting the
C0
2
for commercial use. Contact is working with leading industrial gas supplier BOC, a Linde
company, to assess the highest value commercial options for the use of the C0
2
being
captured at its geothermal facilities. This includes pure C0
2
and combining C0
2
with
hydrogen production for complementary derivative products (e.g. green chemicals).
“We are thrilled with these results. We will see the capture of 10,000 tons of greenhouse gas
emissions per annum from Te Huka on an ongoing basis. This can be eliminated through
reinjection or potentially used in commercial applications where these align to our
decarbonisation strategy,” said Mr Fuge.
In addition, Contact is optimizing the flexibility it can achieve in its geothermal generation
portfolio by shifting up to 11GWh of generation on the Wairākei field between the summer
and winter periods in 2023. This reduces the need to run thermal generation.
The first half also saw Contact preparing for the planned closure of its 44MW Te Rapa
power station in June 2023.
Retail
Mr Fuge said Contact’s retail business has continued with targeted growth in the first half of
2023, with customers on bundled packages up 13% on the prior period.
“We have seen connections increase by more than 20,000 in the half year. We are seeing
significant growth in broadband, with connections up 30% on the prior period, and have
introduced wireless broadband, providing yet another way for our customers to stay connected
at home.”
Contact has expanded its time-of-use offerings, with its Dream Charge plan enabling
customers to charge their EVs at home at cheaper night rates. This adds to Contact’s existing
time-of-use offer, Good Nights, an initiative that’s proven popular with customers who can
access three hours of free power every night from 9pm, shifting their load from peak evening
times and thereby reducing the need for peak thermal generation, lowering carbon emissions.
In December, we were recognised at the NZ Compare Awards, winning Power Provider of
the Year, Best Customer Support; Power and Best Bundled Plan. The awards recognise
excellence and achievement in New Zealand’s broadband, energy and mobile sectors.
Outlook
Looking ahead, Mr Fuge said Contact remains committed to leading the decarbonisation of
New Zealand.
“We are excited about the future. We have a clear strategy, strong balance sheet with
supportive shareholders and a host of 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 interim results announcement will be held at 10am, NZ
(New Zealand) time on 13 February 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
1
2023 interim
results
presentation
Six months ended
31 December 2022
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 reflectspublic
announcements of intention only.
3
1H23 highlights and market update / Mike Fuge, CEO4 -14
Financial results and outlook / Dorian Devers, CFO 16 -28
Supporting materials 31 -41
2
3
1
Agenda
33
4
1
Underlying EBITDAF and profit are shown excluding a $120 million onerous contract provision ($86 million after tax) for AGS. All variances and commentary reflect movements in underlying performance.
2
Refer to slide 36 for a definition and reconciliation of EBITDAF.
3
Refer to slide 24 for a reconciliation of operating free cash flow.
Six months ended
31 December 2022
(1H23)
Six months ended 31
December 2021
(1H22)
Underlying
1
ReportedAgainst underlying
EBITDAF
2
$246m$126m↓24% from $322m
Profit$79m($7m)↓41% from $134m
Profit per share10.1c(0.9 c) ↓41% from 17.2c
Operating free cash flow
3
$60m↓54% from $131m
Operating free cash flow per
share
3
7.7 c↓54% from 16.8c
Dividend declared$110m↑$109m
Dividend declared per share14.0 c→14.0 c
Stay-in-business(SIB)
capital expenditure (cash)
$55m↑57% from $35m
Growth capital expenditure
(cash)
$217m↑87% from $116m
The operating conditions in 1H23were characterised by:
•Nationwide hydro inflows at the 96
th
percentile of
historic. With hydro inflows especially extreme in
North Island catchments. This led to:
•Lower wholesale spot prices.
•Lower thermal generation.
•Higher price separation between North and
South Islands.
•Thermal generation costs remain high:
•High coal and rising carbon costs.
•Continued reductions in forecast gas
deliveries from ageing fields.
•Rising fixed costs will need to be recovered
over less generation as renewable penetration
increases.
•Medium term electricity prices impacted by lower
expected gas availability, high coal and carbon costs,
the end of ‘swaption’ contracts and the notified
reduction in gas storage capacity.
Summary of key financial performance measures
Performance reflects short-term wholesale market
conditions, investing in decarbonisationstrategy
Contact has responded to the short-term
conditions by:
•Reducing thermal generation to reflect
market conditions.
•Preparing to mitigate the impacts of the
modelled reduced storage at AGS for winter
2023 by entering flexible gas contracting
arrangements and if necessary, acquiring
additional gas.
Mediumterm:
•Continuing investment programme to deliver
on its decarbonisation strategy to displace
thermal generation.
•Recognising a $120 million ($86 million after
tax) onerous contract provision for Ahuroa
Gas Storage facility (AGS).
Operating earnings (EBITDAF) was down by
$76m when compared to 1H22 on an underlying
basis¹.
1H23 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
Improving demandoutlook for electricity
Decarbonisationambitions and thermal economics will support growth
Demand
response
Focus
area
What we’ve
learned
Examples of
our progress
Large scale
data centres
Major
industrial
energy users
Green
chemicals
Industrial
process heat
Road
transport
•Attractive baseload
characteristics
•Low emission customers
•Pipeline of hyperscale
data centres announced
e.g. CDC, DCI,
Microsoft, Amazon
✓Demand response is introduced wherever possible when entering into new supply contracts –this is high value to Contact, industrial customers and NZ
✓Will contribute to decarbonisation of New Zealand whilst improving the security of supply at peak periods
✓High degree of customer appetite for demand response mechanisms to be packaged into new contracts
•Data centres under
construction or highly
likely totalling 200MW
•>100MW capacity due to
be added by 2024
•Some barriers remain e.g.
high transmission costs
•Higher carbon pricing
needed to drive increased
rate of boiler conversions
•$69m in confirmed GIDI
funding allocated since
2020
•Supported around 50MW
of new-to-market lower
South Island electricity
demand
•Carbon capture trials
complete at TeHuka. Have
option to reinject or harvest
•Working with BOC, a Linde
company, to assess highest
value commercial options
for C0
2
captured at
geothermal facilities
•Increasing commitment
to decarbonisation
targets by major
energy users
•Significant appetite for
flexible, renewables-
backed electricity
contracts
•Technology advancement
enabling options for
heavy transport
•Increasing uptake of EVs
–21% of all registrations
in December 2022
1
•Expansion of charging
infrastructure required
1
“EVs” includes the number of electric vehicle registrations for December 2022 as reported by the Motor Industry Association. This is inclusive of 100% electric (2,295), plug-in petrol hybrid (389) and petrol hybrid vehicles (1,286).
•Hydrogen export
economics challenging vs
alternatives
•Domestic opportunity for
green chemicals in a
range of hard to abate
sectors
•Working with the HW
Richardson Group to
assess a trial use of
hydrogen for heavy
transport
•Extended time of use retail
offering to EV plan,
introducing Dream Charge
•Long term Tauhara
backed PPAs: Genesis,
Oji Fibre and Pan Pac
•NZAS negotiations
underway
•Working with NZ Steel on
options around
interruptibility
7
Indicative MW (net export to grid)
Estimated plant capacity
factor/ annual generation
Net generation uplift from field resource
after closure of WairākeiA and B
Wairākeigeothermal consents granted
Wairākeire-consent highlights
~168MW
95% / ~1.4TWh p.a.
End of 2023 /
2H 2026
1
~0.4TWh
p.a.
Consent received to operate for the next 35 years on the Wairākeifield, enabling Contact to proceed with its
plans for the replacement of WairākeiA and B legacy geothermal power stations at Te Mihi (GeoFuture)
Targeted final investment decision /
Indicative timing for on-line date
GeoFutureplanned development key features
(capacity / output shown as previously indicated)
✓Consentto continue operations for next 35
years on Wairākeigeothermal steamfield.
✓Consent for large new plant at TeMihi –up
to 180 MW additional to the existing TeMihi
units 1 and 2–providing investment
optionality / flexibility.
✓Will result in significant local investment for
Waikato during construction.
✓Immediate benefits from higher geothermal
mass take –2% higher than current.
✓Reinvigorated partnership with local iwi and
hapu.
✓All Contact’s operational steamfield
discharges into Waikato River cease from
30 June 2026.
Balance sheet prepared, enabling
investment option to proceed fully funded
1
References are to calendar years.
8
Market leading renewable development pipeline
Contact has built a renewable electricity development pipeline of 6TWh, with capability to
deliver
Consented pre-FID (development option)
Consented post-FID (under construction)
2.1
1.1
1.9
3.0
Land access secured / exclusivity
Consenting in progress
1.7
1.3
20232020
3.0
6TWH
Potential options
for future uplift
Planned and
consented
202320242026
>2027
WindSolar
Tauhara
(1.4TWh)
TeHuka
(0.4TWh)
GeoFuture
(1.4TWh)
Roxburgh
(45GWh
2
uplift)
Solar and wind development pipeline advancing, with projects entering consenting stage:
•Contact/Lightsourcebp JV selected by Christchurch Airport to deliver 170MWp (150MW) solar farm
at KōwhaiPark. Subject to a final investment decision, construction targeted to begin in 2024.
•Consenting underway for priority North Island solar farm site (170MWp/150MW) and South Island
wind site (220MW).
•Land access secured for a further development potential of 60MWp (50MW) solar and 450MW wind.
Planned and consented renewable energy development projects
1
Expected generation (indicative):
2025
Potential options for future uplift
Expected generation (indicative):
Tauhara
stage 2
(0.7TWh)
Remaining
capacity
Wairākei
closure
(1.0TWh)
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.
9
National electricity demand
Source: EMI, Contact.
Does not include NZAS
National electricity demand (TWh)
Regional
change (%)
1H23 vs 1H22
Source: EMI, Contact
Market demand
2.5
2.62.6
2.5
2.5
2.5
5.3
5.0
5.3
5.4
5.2
5.5
13.4
13.4
13.5
13.4
13.3
13.2
1H201H18
21.0
1H191H231H221H21
North Island
South Island (ex NZAS)
NZAS
21.1
21.4
21.1
21.3
21.2
0%
+1%
New Zealand electricity demand shows marginal increase on 1H22, despite industrial closures and
weather impacts, indicating underlying demand growth
Total national electricity demand increased
by 0.141 TWh(0.67% from 1H22):
•The decrease in Northland regional
demand (14%) was a result of Marsden
Point refinery converting to an import-
only terminal–a reduction of 260GWh
on the prior half.
•A dry November and December for the
South Island in 2022 saw higher
irrigation demand at major South Island
irrigation demand nodes.
•The 29 GWh decrease in NZ steel
demand was offset by a 24 GWh
increase in Tiwai demand. Tiwai usage
for the period was 580 MW, 8 MW
above contracted usage of 572 MW.
•Our assessment, removing the impact
from major industrial variations,
unusual weather and other known
impacts, is that underlying demand is
up ~2-3%.
0%
0%
(1%)
5%
3%
0%
1%
4%
4%
9%
2%
(1%)
0%
0%
(14%)
1%
1%
2%
10
Hydro generation was up
9% when compared to
1H22, driven by a >40%
uplift in the North Island
(South Island down 2%).
Impacts included:
•
Lower spot wholesale
prices.
•
Higher price
separation between
North and South
Islands.
•
Limited need for
thermal generation
and lower industry
carbon emissions.
Generation by type (TWh)
Generation from generator retailers
-excludes embedded generation
Strong hydro inflows in 1H23 saw actual storage levels higher than mean, reducing reliance on gas and coal.
Source: EMI & MBIE
Source: NZX
1.7
2.2
1.5
1.0
0.9
1.3
3.5
3.6
3.7
12.2
12.9
14.1
1.0
0.2
2.9
2.1
1.3
Gas
1H21
Coal
0.4
1H22
Hydro
1H23
Geothermal
Wind
Non grid generation
22.3
22.1
22.2
0.0
0.5
3.5
2.5
1.0
3.0
1.5
2.0
4.0
Dec-
22
Dec-
20
Jul-
21
Dec-
21
Jul-
22
Mean
Actual
2H212H22
Storage
TWh
National hydro storage
2.91.71.0*
Carbon emissions (mT)
*Carbon emissions for 1H23 Oct-Dec quarter has been estimated using historic conversion rates with actual generation data. The reduction in carbon emissions of 0.7mT CO2-e was due to the decrease in coal and gas generation as a
result of significantly higher hydro generation in 1H23. Some generation has been estimated based on prior period operation
Hydrology and impact on generation mix
Fuel supply
High hydro inflows limited the need for thermal generation
1H231H22
11
11
Aluminium
Demand
Short-term external factors that
can influence the market
Changes as at 31December 2022
in comparison to 31 December 2021
Source: ASX
Short-term
wholesale
electricity
prices
Technical Working
Group concluded that
4PJ of stored gas at
AGS is unavailable for
immediate use
Carbon prices up 13%
to $77/New Zealand
Unit
Methanol pricing
at US$345/t
(down 8%)
Demand was
flat year on year
Aluminium prices lower
(-$411/t, down 10%)
Increase in coal prices
+US$300/t (375%)
Wholesale risks remain elevated
Extreme weather events led
to above mean hydro
storage in last 6 months.
Controlled storage at ~125%
of mean (700GWh above
mean) in December
Forward wholesale pricing reflects current market conditions, including fuel cost and availability risks
40
60
80
100
120
140
160
180
200
220
240
260
280
Q1
23
Q2
23
Q4
24
Q2
25
Q3
23
Q2
24
Q4
23
Q4
26
Q3
24
Q1
24
Q1
25
Q3
25
Q4
25
Q1
26
Q2
26
Q3
26
Elevated wholesale pricing out to 2026
ASX Futures (Quarterly, base period, Otahuhu)
$/MWh
Wholesale market conditions are volatile:
»Near term ASX Futures impacted by lower expected gas availability, high coal and carbon costs
and the end of the ‘swaption’ contracts.
»Impact of renewable generation coming online is being offset by higher expected firming costs
in the medium term.
»Expect market to rebalance from 2027 with further additions of renewable generation and
normalisation of coal costs.
2023 average
$180/MWh
2024 average
$183/MWh
2025 average
$182/MWh
2026 average
$181/MWh
Wholesale market
Quarters prices as at 30 Jun 2022
Quarters prices as at 31 Jan 2023
Calendar year average prices as at 31 Jan 2023
12
12
•Competition remains intense despite sustained high wholesale futures prices.
Market churn continues to reflect this with switching at 19%.
•Tier 1 market share has stabilised(85% Dec-20 & 84% Dec-22) after a
number of years of decline. Tier 2 connections were also relatively flat YoY
(15% Dec-20 & 14% Dec-22). Tier 1’s (primarily Genesis, Contact and
Meridian) added connections as household formation contributed to a
continued ~1% p.a. growth in ICPs.
•Mercury purchased the Trustpowerretail business in FY22 and isthe largest
retailer by ICP (26% market share).
•2degrees and Vocusmerged on 1 June 2022 becoming the third largest telco,
alongside providing energy and insurance products, and are now the leading
Tier 2 in electricity connections growth (+13k).
•Contact electricity connections+1k YoY maintaining 19% market share.
Change in customer electricity connections (000s)
31 December 2020 –31 December 2022
2yr % change2yr ICP delta (1000s)
Retail electricity tariff changes (c/ kWh)
Tier 2: +12k connections
•Despite sharply higher wholesale prices over the last four years, tariffs were up
by a compound annual growth rate of only 2%. Average tariff increases for the
last year of 3% remain materially below consumer price inflation (>7%).
•Households have been largely insulated from higher wholesale prices to date
because of fixed price residential contracts and retailers’ longer-term view of
pricing that rides through short-term volatility.
•Continued firming future wholesale prices and wider industry costs will need to
be recovered by retailers. The real residential unit cost per unit of electricity has
fallen in every year since 2018.
12 months
ended:
Tier 1: +54k connections
Source: EMI
Source: MBIE
4%
4%
-4%
10%
-14%
-2%
2%
8%
26%
-30
-20
-10
0
10
20
30
40
OtherPulseGenesis*MeridianContactManawa
Energy
NovaMercury /
Trustpower*
FlickElectric
Kiwi
2degrees
/ Vocus*
161%
17.1
17.4
18.1
19.4
20.1
20.9
12.2
12.3
12.1
11.1
11.3
11.6
30.5
Nov-19Nov-22Nov-17Nov-18Nov-20Nov-21
29.3
29.7
30.2
31.5
32.5
+2%
Retail competition remains intense
Retail electricity market
Retailer’s long-term view of pricing rides through short-term wholesale input cost volatility
Lines (c/kWh)
Energy & Other (c/kWh)
*Genesis customer electricity connections consolidates Ecotricity(held 70% of Ecotricityas at 28 February 2022). Mercury completed the purchase of the Trustpowerretail business on 1 June 2022. 2degrees completed the purchase of
Vocuson 1 June 2022. Companies have been grouped together as relevant for the period under review despite being in different ownership.
1
Compound annual growth rate.
1
13
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. Work on the next Emissions Reduction Plan will also start in 2023.
2
Covering electricity, hydrogen, and industry decarbonisation. Terms of Reference have been released.
3
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
3
Significant
increase in
GIDI
subsidies
Resource
consenting
reform
Transmission
pricing and
grid
upgrades
Emissions
Reduction
Plan
1
Potential electricity demand impactPotential renewable generation impactPotential wider electricity sector impact
In progress
Announced
New
Zealand
Battery
Project
feasibility
Climate change and regulation
14
Topical regulatory matters
Medium term spot and hedge market prices continue to
be higher than long term averages due to coal prices,
gas availability and the cost of carbon. This is increasing
pressure on unhedged energy intensive industries.
The industry, Transpowerand the EA are paying close
attention to capacity in winter 2023. The industry CEO
forum is working closely with the EA to minimisethe risk
of any shortage in 2023.
Wholesale
market
security
Contactis exploring further renewable generation opportunities across geothermal, wind and
solar to reduce future impacts from thermal fuel volatility.
Contactis working with customers to smooth out pricing volatility through long-term contracts.
Contactis leading the development of the demand response market for C&I customers, and
has introduced time-of-use offerings for retail customers, helping to reduce load during peak
periods.
Contactis continuing to engage with the EA on the longer-term impacts of market volatility.
The sector is now entering a period of intense investment to both decarboniseexisting
generation and build new generation to meet future demand.
Key themes
What Contact is doing
NZ Battery
Project
The Government is assessing options to address
New Zealand’s dry year risk with 100% renewable
generation. This includes assessing its initially
preferred solution of pumped hydro at Lake
Onslow.
InOctober 2022, Boston Consulting Group
released a report “The Future Is Electric” which
showed that a range of industry-led solutions were
available to address the dry-year risk without the
need for the proposed Lake Onslow project.
Contactsupports further analysis to address dry year risk. Multiple options exist that will require
careful evaluation, including interruptible green hydrogen, interruptible load for other major
customers and grid-scale batteries.
Contactcontinues to assess low cost, low capital options to support decarbonisationthrough
market-led thermal solutions.
15
Financials
16
Key themes from the financial results
Extreme hydrology impacts
1H EBITDAF, well positioned
for 2H
$120m non-cash onerous
contract provision recognised on
gas storage contract
Sales channels repricing,
further opportunity exists
Capital Markets Day to be
held in late May 2023
Higher operating costs to support
growth and sustainability strategy
New renewable electricity
from projects under
development to be sold into
high priced futures market
17
Profit ($m)
Excluding the onerous contract provision, EBITDAF down $76m (underlying) reflecting results from a record
prior period and lower renewable generation
Loss of $7m for 1H23
EBITDAF ($m)
Higher
carbon unit
costs on
geothermal
generation
Lower wholesale
prices saw lower
realised CFD and
merchant sales
and limited ability
to generate
marginal thermal
generation
Renewables
down 391GWh
as hydro
generation
reverted to mean
Fixed costs higher
with increase in
other operating
costs (-$20m) and
higher electricity
transmission costs
(-$4m) from the
removal of ACOT
6
4
3
1
1H23 results
1H22 profit
Net interest
costs
EBITDAFDepreciation
& Amortisation
TaxFair value of
financial
instruments
1H22
EBITDAF
Renewables
Gas, carbon
acquired
generation price
Fixed costs
1H23 EBITDAF
before and
after onerous
contract provision
322
126
51
120
33
25
7
2
24
246
-76
Fixed Price
Variable
Volume
repricing
Other income
9% increase
in yield from
C&I, retail
and long-term
channels
2
Other income
lower as
improvement to
gas gross
margin offset
by market
making losses
(-$10m yoy)
5
Merchant
and CFD
sales, net of
thermal
support
1H23 profit
before and
after onerous
contract
provision
Onerous contract provision before tax
Reported EBITDAF
Reported profit
Onerous contract provision after tax
134
86
18
21
-7
0
79
-76
-18
-55
18
Wholesale EBITDAF ($m)
Retail EBITDAF ($m)
Corporate / unallocated costs ($m)
Business performance by segment
EBITDAF down by $76m
Refer to slides 19 -21
Refer to slide 22
11
47
12
268
Generation
costs
(including
acquired
generation)
1H22Total
contracted
revenue
Trading,
merchant
revenue
and losses
1H23
Underlying
315
-48
16
1
18
1H221H23
1
Electricity
Volumes
36
Electricity
Prices
Opex
4
Other
products*
2
-15
Electricity gross margin
(-$17m)
Electricity
and network
cost inflation
Price recovery
*Other products includes retail gas and broadband gross margins
Simply and Western included within Wholesale EBITDAF
1H23 results
-10
-22
3
1H22One-offsGrowth &
sustainability
8
1
Cost
inflation
1H23
Underlying EBITDAF is shown excluding a $120 million onerous contract
provision for AGS
One-off movements from 1H22 include the Holidays Act
provision reversal and SaaS asset write off (together totalling
$6m). 1H23 included execution programmesetup costs and
industry report ($2m).
19
Electricity generated or acquired (GWh)
Costs down $11m on reduced thermal generation volumes, up $1.6/MWh on a higher proportion of fixed costs
1H221H23
Electricity generated or acquired costs ($m)
Generation costs
1H23 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 down 338GWh on 1H22 (-14%),
64GWh (+3%) above mean year expectations.
•
Geothermal volumes were 53GWh down on prior period
(-3%), 19GWh (-1%) below mean year expectationsas a
result of the 5 yearly Wairākeiplant outage and
geothermal volumes being conserved for 2H23.
•
Thermal volumes were 116 GWh (-29%) lower than
1H22 as a result of the hydrological conditions and low
spot wholesale prices.
Costs
•
Renewable generation costs were up $6m on 1H22
(13%) on removal of ACOT payment for Te Huka and
higher unit carbon costs on geothermal and operating
cost inflation.
•
Thermal generation costs were down by $10m (-14%) on
lower thermal volumes.
•
Thermal fuel costs of $120.1/MWh (1H22:
$121.4/MWh). With gas costs marginally lower
(1H22: $9.2/GJ, 1H23: $7.9/GJ) and carbon
prices (1H22 $34/unit, 1H23 $43/unit) higher.
1,659
1,606
2,391
2,053
407
291
162
131
Hydro
Geothermal
1H231H22
4,620
Acquired
Thermal
4,081
47
5
54
49
12
55
16
72
40
62
28
25
12
16
12
11
12
25
16
Generation
type
3
Cost
type
Generation
type
Cost
type
149149
138138
-11
91%
Renewable % of
own generation
93%
$32.2/MWh
$33.8/MWh
*Gas storage costs exclude $120m onerous contract provision for AGS.
Development
20
1,988GWh
$121.0/MWh
Contracted
revenue ($m)
Diversified mix of long-term and ASX linked sales channels
571GWh
$107.6/MWh
+60GWh
+$17.9/MWh
-686GWh
-$31.9/MWh
•Fixed price variable volume electricity sales to the Retail segment and C&I
customers ended159GWh higher than 1H22 (+$16m). Prices were up $22/MWh
to $124/MWh (+$58m), reflecting higher wholesale prices over the three
preceding years.
•Strategic fixed price sales were 99GWh higher than 1H22 (+$5m) reflecting more
volume under the NZAS support contract. Prices were down by $1.4/MWh as
inflationary adjustments to long-term sales where not enough to offset the mix
change from lower NZAS price (-$1m).
•CFD sales volumes were down by 686GWh (-$96m) on lower renewable
generation and prices that did not support the sale of thermal generation. Prices
were down by $32/MWh reflecting hydro inflows (-$18m).
•Operating costs to support commercial and industrial customers loweras Simply
acquisition synergies captured.
•Other income was $12m lowerpredominantly due to market making losses in
1H23 (1H22: -$2m, 1H23: -$12m)
Wholesale contracted revenue
24
588GWh
$134.0/MWh
+99GWh
+$38.0/MWh
199
241
47
79
175
61
34
38
19
19
469
Other net income
-5
CFD sales
1
-6
1H22
-11
1H23
C&I channel
and decarbonisation
support costs
Steam sales
Strategic fixed price sales
C&I net price
Retail segment sales
422
-47
1H23 results: Wholesale business
723GWh
$53.2/MWh
+99GWh
-$1.4/MWh
Year-on-year
changes to
volume and price
1H23 volumes
and price
21
Trading EBITDAF ($m)Long / short position (GWh)
$103.6/MWh
8.6%
($9.0 / MWh)
13.0%
($7.5/ MWh)
•Rainfall events throughout the half
significantly reduced market price
vs. 1H22 with average spot price
down 46%. Critically, events were
nationwide vs 1H22 which was
biased to Clutha catchment.
•This lead to significant retraction
in hydro and thermal volumes
generated (-452 GWh) and
corresponding reduction in
merchant generation volumes
(-110 GWh) and short order CFD
channels (-426 GWh).
•Softermarket prices reduced
LWAP / GWAP cost in absolute
terms.
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
$57.8/MWh
Spot purchases and sell
CFD settlement
Spot sales and buy CFD
settlement
Merchant generation
33
12
-38
-29
1H221H23
-5
-17
320
209
4,253
-4,253
1H22
3,827
-3,827
1H23
320
209
1H23 results: Wholesale business
LWAP/GWAP
losses
22
1
Retail business performance
EBITDAF ($m)
Managing through elevated wholesale input costs while growing market share through multi-product strategy
Revenue & Tariff
1
($m)
1H221H23Variance
$m$mTariff¹$mTariff
Electricity gross revenue
4504862603611
PPD
2
not taken
21(1)
Incentives paid
(3)(3)(0)
Net revenue(cash)
4494842593510
Capitalisedincentives
31
Amortisedincentives
(4)(2)
Net revenue(P&L)
4484832593510
Gas revenue
43483255
Broadband revenue
2532707(1)
Other income
352
Total revenue
51956849
Contract Asset (closing)
66(0)
# of connections (closing)
552k571k20k
Cost to serve/connection
(6mths)
$62$61($1)
1
Tariff is $/MWh for electricity, $/GJ for gas and $ per month per customer connection for broadband
2
Prompt Payment Discount
44
41
24
3
3
5
-33
-35
1
1H221H23
16
1
Gross Margin (GM) is Revenue less Cost of Goods (Networks,
meters, levies, energy, carbon and broadband)
1H23 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 $15m on 1H22 as a
$36m increase in electricity costs was not fully
passed through to customers.
Continued to smooth the impact of higher electricity
costs for customers and target average increases
below general inflation:
•Electricity net price at ICP improved by 6% from
1H22 with targeted retail price rises partially offset
by increased network and meter costs.
•Around 79% of customers received a price
increase in the last 12 months.
•Retail energy tariffs will need to rise to reflect
higher wholesale electricity, gas & carbon costs
since 2018.
Connection growth slowed in the half given increased
focus on multiproduct connections and value.
•Total connections still +20k on 1H22 primarily
through continued growth in broadband.
•Multiproduct customers up 13% on 1H22, including
through new products with launch of fixed wireless.
Cost to serve –digitised interactions continue to grow
driving improvements in cost to serve per connection
(down $1/connection on 1H22) and customer
experience (NPS +6 points on 1H22).
23
Other operating
cost movement
($m)
Base
movement
Non-recurring
•Holidays Act provision released in 1H22 post successful Metro Glass appeal,
partially offset by accounting adjustments related to software as a service
(SaaS), write down of thermal development costs.
•1H23 one-off impacts represent strategic execution programme set up costs,
Contact’s share of BCG industry report, cost of retaining TeRapa employees
until plant closure and one-off back pay of new parental leave policy (Grow
Your Whanau).
Base movement
•General inflation of 5-7% impacting operating costs. These have been seen
across the business, including labour cost.
•Headwinds include increase in travel expenditure in a post-Covid environment.
•Base savings include productivity savings and shift in focus from prior BAU
activity to growth initiatives.
Growth and sustainability
•$1m incremental investment related to retail connection growth.
•Operating costs to deliver on strategic growth priorities including;
•Ongoing costs of transformation.
•Increase in renewable development (decarbonisation demand growth,
wind and solar) which flows through operating expenditure in early
stages.
•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
1H23 results: Operating costs
Headwinds
1H22 One-off Impacts
1H23 One-off Impacts
3
4
6
6
One Off Impacts1H22
1
1
UnderlyingGrowth and
sustainability
1H23
98
9
6
118
Non-recurring
24
•Lower EBITDAF on soft short-term wholesale market conditions.
•Working capital increase of $43m in 1H23. This relates to higher levels of gas and carbon
inventory following lower thermal generation in 1H23. This is expected to reverse as more
thermal generation is required over winter.
•Tax paid is up $11m on higher provisional tax payments based on strong FY21 earnings.
•Stay-in-business capital expenditure (cash) increase of $20m is linked to accelerated spending
identified to support higher asset availability and output as well as an SAP systems upgrade
project.
6 months
ended
31 Dec 2022
6 months
ended
31 Dec 2021
Comparison
against 1H22
EBITDAF (underlying
1
)$246m$322m↓($76m)
Workingcapital changes($43m)($69m)↑$26m
Taxpaid($76m)($65m)↓($11m)
Interest paid, net of interest capitalised($12m)($15m)↑$3m
SIBcapital expenditure($55m)($35m)↓($20m)
Non-cash items includedin EBITDAF-($7m)↓$7m
Operating free cash flow (OpFCF)$60m$131m↓($71m)
Operating free cash flow per share7.7 c16.8 c ↓(9.1c)
Cash conversion (OpFCF/EBITDAF)24%41%↓(17%)
Commentary
Cash conversion for 1H23 impacted by higher tax paid, SIB capex and an increase in gas and carbon
inventory
Cash flow and capital expenditure
Strategic investments / acquisitions
Growth investment
Dividends paid
Sources and uses of cash ($m)
60
164
18
15
5
2
SourcesUses
415415
234
328
4
Cash Movement
Debt drawdown
OpFCF
1H23 results: Cash flow
DRP
Gas sale & repurchase
1
Underlying EBITDAF is shown excluding a $120 million onerous contract provision for AGS.
Sale of asset
25
•Face value of borrowings (excl. leases)
increased by $329m to $1,354m from 30 June
2022.This increase in debt levels is due to the
construction of the TeHukaand Tauhara
geothermal power stations.
•Additional funding activity will be undertaken in
2H23 to finance these ongoing construction
projects.
•Bank facilities have been increased to allow
greater use of the low-cost CP program without
introducing any refinancing risk and provides
additional capacity to cover prudential
requirements for ASX trades.
•The bank facilities are all sustainably linked and
have been updated to align with the Contact26
strategy to lead the decarbonisationof New
Zealand.
•Gearing increased to 30% at 31 December
2022, up from 23.5% at 30 June 2022.
•The increased debt levels combined with higher
floating interest rates have resulted in a slightly
higher average interest rate on gross debt.
A green and sustainably-linked debt portfolio aligned to our Contact26 strategy
Closing net debt ($m)
Face value of borrowings less cash
Interest rate (%)
Weighted average gross interest
1
on average borrowings
Net debt to EBITDAF (x)
Includes S&P adjustments (prior to FY20, AGS was treated as a lease)
Borrowing maturities ($m)
Average tenor of 6.4 years as at 31 December 2023
Strongbalance sheet
1.Gross interest includes all interest on borrowings, bank commitment fees and deferred financing costs. Unwind of leases, provisions and capitalised interest not included.
2.Based on a normalised and expected EBITDAF of $550m.
1,410
990
1,036
774
1,025
1,354
-150
-168
-163
FY18
38
1,014
FY19
-3
-47
25
22
-44
FY20
21
FY21
25
FY22
1,445
26
1H23
968
645
882
1,216
Lease obligationsCash on handBorrowings
4
225
153
100
136
350
88
75
14
50
250
61
300
FY25FY23
77
FY24
7
FY26
7
FY27
4
FY28 -
FY29
FY52
235
357
182
493
342
Undrawn bank facilitiesNEXI
USPPCapital bondsDrawn bank facilities
Domestic bonds
3.1
2.3
2.4
1.2
1.5
2.2
FY22FY19FY18FY20FY21HY23
1,476
1,207
1,031
963
902
1,221
FY19
5.4%
FY20
5.2%
5.1%
FY18
5.2%
FY21
5.3%
FY22
5.4%
1H23
Average gross interestAverage gross debt
1H23 results: Key balance sheet metrics
2
26
Ordinary dividends ($m)
Declared
Final dividendInterim dividend
% pay-out of operating free cash flow
Dividend for 1H23
2323
2121
14
1616
1414
35
FY211H23FY19FY20FY22
3939
35
cps
Interim dividend for 1H23 of 14 cents per share
•Interim dividend of 14 cents per share is imputed to 86% or 12 cents per share for qualifying shareholders.
•Record date of 10 March 2023; payment date of 30 March 2023.
•The NZD/AUD exchange rate used for the payment of Australian dollar dividends will be set on 21 March
2023.
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.
•For this dividend, there will be no discount offered and Contact will have the right to terminate or suspend
the plan at any time.
•Dividend reinvestment plan application forms must be in by 13 March 2023to confirm participation in the
plan.
•Trading period for setting price for DRP is 9 March 2023 to 15 March 2023. DRP strike price will be
announced: 16March 2023
97%
72%
84%
182%
82%
3939
35
35
14
27
Channel yields suggest an increase in
normalisedEBITDAF
12
16
28
16
13
Estimated FY23 updated
for known factors
FY23 normalised¹
and expected
6
14
1H23 actual variance to
expectations (slide 38)
-34
2H23 performance
forecast vs normalised
550
530
¹ See slide 40 for assumptions underpinning FY23 normalisedand expected earnings
Renewable generation vs mean
Wholesale market sales (CFDs and long spot sales)
Market making
Fixed channel price (Retail, C&I and Strategic)
Expect partial recovery of 1H impacts with sustainable pricing changes
EBITDAF ($m)
28
Guidance confirmation
Updated FY23
guidance
1H23 resultChange to prior guidance
Stay in business capital expenditure (cash)$110 -120m$55m+$22m
Sustainable SIB capex remains $65m p.a. An additional
$100m SIB capex above this level is expected between
FY22-27 to support higher asset availability and output as
well as the SAP system upgrade. The increase in
guidance reflects pull-forward elements of this programme
and $6m capital costs for the Wairkeireconsenting
mitigation agreements in the FY.
Growth capital expenditure (cash)$465–565m$217m-
Depreciation and amortisation$220–230m$111m($10m)
Net interest (accounting)$35 –45m$19m+$5m
Adjusted for unwind of onerous contract provision and
higher floating interest rates.
Cash interest(in operating cash flow)$20 –30m$12m+$10m
Timing of interest payments with updated debt facilities
and higher floating interest rates.
Cashtaxation$110 –120m
$76m (2/3
rd
of
payments in 1H23)
-
Corporate costs$42m$22m-
Target ordinary dividend per share35 cps (40%/60%)14 cps (interim)-
29
Questions
30
Supporting
materials
31
Contact generation output sold to the national grid (GWh)
Generation and sales position
1,552
1,726
1,652
1,649
1,524
1,659
1,606
2,073
1,635
2,045
1,886
1,984
2,391
2,053
685
966
836
825
870
360
1H171H181H211H191H201H22
246
1H23
Thermal
generation
Hydro
generation
Geothermal
generation
4,310
4,327
4,359
4,533
4,378
4,411
3,905
Operational data
Renewable % of
own generation
sold to grid
78%82%
81%
84%
80%
92%94%
Geothermal generation (GWh)
Te Huka
Ōhaaki
Poihipi
Wairākei
Te Mihi
Geothermal generation was 53GWh lower than 1H22 primarily as result of a Wairākeistation statutory
inspection (once every 5 years)
488
719
716
709
559
692
690
612
539
486
493
567
531
489
199
209
203
181
129
168
154
159
161
155
171
165
170
165
104
107
94
1H201H17
95
99
1H19
1,524
99
1H18
92
1H211H221H23
1,552
1,726
1,652
1,606
1,649
1,659
Hydro generation (GWh)
The large spill in 1H23 was a result of strong hydrology inflows coming in three main rain events coupled with
some longer outages which effected our ability to generate
2,213
1,780
2,148
2,789
2,432
2,758
3,152
-30
-175
-67
-35
-707
-107
-960
1H20
-73
1,886
-73
1H17
-110
1H181H19
-197
1,984
1H21
-274
-260
1H22
-139
1H23
2,073
1,635
2,045
2,391
2,053
Inflows stored include uncontrolled storage lakes
Inflows
Inflows
stored
Spill
Thermal generation (GWh)
Thermal generation volumes were 115GWh lower than 1H22 as a result of the strong renewable generation
and low wholesale prices
298
463
649
593
620
168
161
275
369
69
119
130
87
111
133
114
111
117
104
67
52
2
51
50
3
2
0
1H191H171H18
887
48
4
1
50
1H201H21
2
47
736
1H22
45
17
1H23
1,016
875
918
407
291
TeRapa
Spot
Whirinaki
TeRapa
Direct
Peakers
TCC
Thermal generation volumes were 114GWh lower than 1H22 as a result of the strong renewable
generation and low wholesale prices
32
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
20
0
10
40
30
50
94%
1H17
101%
1H18
97%
1H19
100%
1H20
95%
1H21
100%
1H22
96%
1H23
-4%
30.6
31.0
32.3
30.7
30.3
31.4
29.8
1H221H231H201H171H181H191H21
-5%
Geothermal fuel performance
Taranaki combined cycle (TCC)
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
1H1937763%39%64911978
1H2037778%36%59311367
1H2137796%37%62012779
1H22377100%10%16718331
1H2337789%10%16110717
Hydro
Geothermal
Stratford Peakers
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
1H1978495%59%2,045129265
1H2078494%54%1,88698184
1H2178485%57%1,984110218
1H2278483%69%2,39190215
1H2378487%59%2,05352107
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
1H1942591%88%1,652137226
1H2042594%88%1,649106175
1H2142586%81%1,524118180
1H2241096%92%1,660105175
1H2341094%89%1,6065689
TeRapa (spot generation only)
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
1H1920265%8%6921415
1H20
202
63%13%11915218
1H21
202
86%14%13015120
1H22
202
74%10%8721619
1H23
202
57%2%171903
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
1H194198%63%11416118
1H2041100%61%11111613
1H214199%65%11712214
1H2241100%57%10410811
1H234195%34%67554
Plant availability
Availability Factor calculation includes all station outages (Planned, Maintenance, Forced) but does not consider plant deratings.
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
1H1915898%1%45192.1
1H20
158
97%0%12690.4
1H21
158
91%0%33050.8
1H22
158
98%0%27831.8
1H23
158
97%0%22740.4
Whirinaki
33
Haweastorage (GWh)
Gas storage (PJ)
Closing storage
Closing storage (current)
Fuel storage movements
Source: NZX hydro
53
159
152
257
90
175
166
260
113
252
294
351
244
299
229
324
190
323
-146
-302
-246
-412
-214
-237
-231
-337
-184
1H192H191H202H201H212H211H222H221H23
Inflows
Opening storage
Releases
159
152
257
90
175
166
260
113
253
7.5
5.6
4.4
5.0
6.1
5.0
5.8
7.8
4.7
0.8
0.6
1.5
2.2
0.8
1.7
2.4
0.5
2.7
-2.7
-1.7
-1.0
-1.1
-1.9
-0.9
-3.5
-0.7
-4.0
1H192H191H202H201H212H21
-0.4
1H222H221H23
Gas Injected
Gas Extracted
Opening Storage
Long-term storage
5.6
4.4
5.0
6.1
5.0
5.8
7.8
4.7
2.7
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).
Contact has several mitigations available to limit the impact for winter 2023, including entering flexible gas contracting arrangements and if
necessary, acquiring additional gas.
0
Transferred to
long-term storage
(PJ)
0
0
0
0
0
0
0
4
34
Contracted gas volumes (PJ)
Uses of gas (PJ)
Gas storage monthly injections and extractions (PJ)
Contracted and stored gas
Storagebalanceat31December2022was6.7PJs,
ofwhich2.7PGisimmediatelyaccessible
Gas injectedGas extracted
4.0
7.6
8.1
3.4
0.9
0.1
7.0
4.5
4.5
4.5
6.1
1.7
7.0
3.4
4.5
2.0
5.3
7.4
7.8
6.5
2.3
5.5
5.1
0.0
CY20CY18CY21CY23
1
CY19CY24
2
-0.2
CY22
0.5
18.4
16.6
16.9
14.6
15.5
13.4
14.0
-0.21
-0.03
-0.08
22-
Jan
0.15
0.35
0.04
22-
Jul
22-
Mar
-0.38
0.10
-0.67
22-
Apr
0.01
-0.08
0.13
-0.90
22-
May
0.03
-0.96
22-
Jun
0.50
1.08
22-
Sep
-0.02
-0.72
0.29
0.07
22-
Feb
22-
Oct
22-
Aug
22-
Nov
0.43
-0.04
-0.08
22-
Dec
10.3
8.1
9.4
9.3
9.5
6.6
9.8
-1.1
1.1
-0.7
-2.0
3.1
-2.0
-7.9
-5.3
-8.2
-6.7
-4.3
-6.5
-3.3
-1.8
-1.4
-1.7
-1.4
-1.6
-1.3
-1.6
-1.5
-1.9
-5.5
-0.6
1H221H211H20
-0.5
-0.1
2H20
-0.2
-0.5
2H21
Wholesale sales
2H221H23
Net extraction (injection)
Generation
Customer sales
Purchases
Short-term gas
Genesis
Swap
Pohokura (OMV)
Maui
Operational data
1
MauiandPohokuravolumesforCY23reflectforecastvolumes.
Contractedvolumesintheperiodare:Maui10PJandPohokura7PJ.
2
NoforecastavailableatthistimeforCY24.Contractedamountsshown.
35
Contractual fuel position sufficient to
support expected sales position
Fuel position
Portfolio requirements for thermal generation (TWh)
Gas supply and demand 2023 (PJ)
Hydro variation >>
•Hydro generation in FY12
** Assumes mix of TCC and peakergeneration (portfolio heat rate (9GJ/MWh))
GeothermalExpected
2023
generation
from
onstream
assets
(including
losses)
Hydro in
"extreme
dry" year*
Maximum
thermal
required
"Extreme
dry" to
"mean"
year swing
Mean
thermal
required
Co-
generation
Maximum
thermal
required
"Mean" to
"wet" year
swing
Minimum
thermal
required
Gas forecast
under contract
and swap return
5.4
13.5
2.0
2.7
2.7
1.4
CY23 Position
Mean Year
demand
Retail
Mean Thermal
Gas in storage
Co-generation
10.1
Short term gas purchases
17.6
7.9
1.6
0.6
0.3
-1.0
-3.3
-0.2
-0.3
-2.9
Gas available for an
extreme dry year
7.5PJ (~1TWh
through TCC)
In addition, Contact has
access to stored water in
Haweato support risk
management
36
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:
6 months ended
31 December 2022
6 months ended 31
December 2021
Variance onprior year
$m%
Underlying
Reported
ReportedAgainst underlying
Profit79
(7)
134(55)(41%)
Depreciation and
amortisation
1111291814%
Change in fair valueof
financial instruments
6(13)(19)(146%)
Net interest expense191900%
Tax expense32(2)532140%
EBITDAF246126322(76)(24%)
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 1H22 are as follows:
•Depreciation and amortisation: decreased by
$18m (14%) on 1H22 primarily resulting from
acceleration of depreciation for aspects of SAP due
to SAP upgrade project in 1H22.
•Net interest expense: In line with 1H22 with higher
averageborrowings being offset by higher
capitalisationof interest relating to the Tauhara and
Te Huka projects.
•Tax expense for the period decreasing by $21m
following lower operating earnings.
Non-GAAP profit measure
Underlying EBITDAF and profit are shown excluding a $120 million onerous contract provision ($86 million after tax) for AGS. Allvariances and commentary reflect movements in underlying performance.
37
Historical financial information
Unit1H181H191H201H211H22
1H23
Underlying
1
Reported
Revenue$m1,1901,3631,1101,1411,141994
Expenses$m9541,072889895819748868
EBITDAF$m236291221246322246126
Profit$m58276597813479(7)
Operating free cash flow$m14120312015713160
Operating free cash flow per sharecps19.728.316.821.916.87.7
Dividends declared cps13.016.016.014.014.014.0
Total assets$m5,3905,1404,8504,7384,9785,408
Total liabilities$m2,6632,2972,1702,2122,0272,748
Total equity$m2,7272,8432,6802,5262,9512,660
Gearing ratio
2
%35.429.729.931.119.330.6
Historic performance
1
Underlying expenses, EBITDAF and profit are shown excluding a $120 million onerous contract provision ($86 million after tax)for AGS.
2
Gearing ratio is calculated as: Senior debt -including finance lease liabilities/(Senior debt -including finance lease liabilities + Equity).
38
1H231H22
Six months ended 31 December 2022Six months ended 31 December 2021
VolumeGWAPVolumeGWAP
Note: this table has not been rounded andmight not addGWh$/MWh$mGWh$/MWh$m
Electricity sales to Retail segment1,988 121.0 240.6 1,928 103.1 198.7
Electricity sales to C&I (netback)781112.3 87.8 67181.7 54.8
Electricity sales –Direct45165.4 7.5 47132.7 6.2
Electricity sales to C&I826 115.2 95.2 718 85.0 61.0
CfDs–Tiwai support48635.0 17.0 39735.0 13.9
CfDs-Long term sales210116.4 24.4 264102.1 26.9
CfDs-Short term sales361102.4 37.0 993149.4 148.4
Electricity sales –CFDs1,057 74.2 78.4 1,654 114.4 189.2
Total contracted electricity sales3,872 107.0 414.2 4,300 104.4 448.9
Steam sales336 55.4 18.6
36151.818.7
Other income
(15.2)0.9
Net income on gas sales1.2
1.2
Net income on electricity related services3.3
(0.9)
Net other income
(10.7)1.2
Total contracted revenue4,208 100.3 422.2 4,661 100.6 468.9
Generation costs
1
3,950(30.8)(121.8)4,458(27.8)(123.8)
Acquired generation cost131(122.5)(16.1)162(153.7)(24.9)
Generation costs (including acquired generation)4,081 (33.8)(137.9)4,620 (32.2)(148.7)
Spot electricity revenue3,90557.6 225.1 4,411102.7 453.1
Settlement on acquired generation13162.7 8.2 162128.4 20.8
Spot revenue and settlement on acquired generation (GWAP)4,036 57.8 233.3 4,573 103.6 473.9
Spot electricity cost(2,770)(69.8)(193.4)(2,599)(117.3)(305.0)
Settlement on CFDs sold(1,057)(53.6)(56.7)(1,654)(105.2)(173.9)
Spot purchases and settlement on CFDs sold (LWAP)(3,827)(65.3)(250.0)(4,253)(112.6)(478.9)
Trading, merchant revenue and losses
(16.7)(4.9)
Wholesale EBITDAF underlying
1
267.6315.2
Onerous contract provision
(120.0)
Wholesale EBITDAF reported
147.6315.2
Wholesale segment
Segmental performance
1
Generation costs and wholesale EBITDAF underlying are shown excluding a $120 million onerous contract provision ($86 million after tax) for AGS.
39
Residential electricityunit
1H201H211H221H23
Residential gasunit
1H201H211H221H23
Average connections#355,216357,756367,199
381,222
Average connections#61,95960,56363,18266,796
Sales volumesGWh1,3281,3491,408
1,445
Sales volumesTJ911954970881
Average usageMWh per ICP3.73.83.83.8Average usageGJ per ICP14.715.715.413.2
Tariff$/MWh248.2251.1251.5261.4Tariff$/GJ30.631.332.638.1
Network, meters and levies$/MWh-122.5-116.2-115.9-118.2Network, meters and levies$/GJ-17.3-15.3-16.2-20.7
Energy costs$/MWh-91.6-101.1-110.8-128.7Energy costs$/GJ-7.6-8.3-11.3-10.2
Gross margin$/MWh34.133.824.814.5Carbon costs$/GJ-1.4-1.4-2-4.2
Gross margin$ per ICP1411279555Gross margin$/GJ4.36.33.23.0
Gross margin$m50453521Gross margin$ per ICP70995039
Gross margin$m4633
SME electricityunit
1H201H211H221H23
SME gasunit
1H201H211H221H23
Average connections#55,29551,40748,32347,702Average connections#3,9913,8583,9183,656
Sales volumesGWh533465392421Sales volumesTJ845720628635
Average usageMWh per ICP9.69.08.18.8Average usageGJ per ICP211.8186.7160.4173.6
Tariff$/MWh226.7230.7239.0249.2Tariff$/GJ14.915.818.623.1
Network, meters and levies$/MWh-113.5-104.4-113.0-113.0Network, meters and levies$/GJ-5.4-7.9-8.7-8.4
Energy costs$/MWh-89.3-99.7-109.0-129.8Energy costs$/GJ-7.6-8.3-11.3-10.2
Gross margin$/MWh23.926.517.06.4Carbon costs$/GJ-1.4-1.4-2.0-4.2
Gross margin$ per ICP24224013856Gross margin$/GJ0.5-1.8-3.30.3
Gross margin$m131273Gross margin$ per ICP97-474-53254
Gross margin$m0-2-30.2
Broadband
unit
1H201H211H221H23
Retail segment EBITDAF
1H201H211H221H23
Average connections#17,03833,19757,49874,974Electricity Gross margin$m58584124
Tariff$/cust/mth70.765.271.870.4Gas Gross Margin$m4513
Network, provisioning, modems$/cust/mth-68.9-74.0-61.6-62.8Broadband Gross Margin$m0-244
Gross margin$/cust/mth1.8-8.810.27.6Total Gross Margin$m62614631
Gross margin$m0-244Other income$m2335
Other operating costs$m-35-33-33-35
Retail segment EBITDAF$m3030161
Corporate allocation (50%)$m-7-7-5-11
Retail EBITDAF$m232311-10
EBITDAF margins (% of revenue)%4.70%4.60%2.10%-1.80%
Retail segment
Historic performance
During 1H23 metering costs of $6m, which were previously in operating costs to serve were reclassified into networks meters and levies (COGS) to better reflect the nature of the costs. Comparisons have been restated.
From FY22 onwards, ICT costs previously included within operating costs for the retail business have been moved to corporate (prior years have not been restated).
40
Strategic fixed price725GWh$54/MWh $39m
CFDs640GWh$135/MWh$86m
C&I600GWh$140/MWh$84m
Retail2,000GWh$132/MWh$264m
Other income³$34m
$507m
Hydro1,989GWh$0/MWh-$0m
Geothermal1,625GWh$3/MWh-$5m
Thermal⁴525GWh$122/MWh-$64m
Acquired67GWh$150/MWh-$10m
-$79m
Length⁵$40mTransmission/Storage-$30m
Location losses⁶-$40mOperatingexpenses-$118m
Total$0mTotal-$148m
1H23 assumptions that deliver expected & normalised EBITDAF of $550m over a financial year
EBITDAF reconciliation to 1H23
Hydrology & Asset
availability optimise generation
3
4
Total
x
=
Access to and price of fuel* drives
financials & risk position
Merchant and CFD sales
Normalised & Expected
Higher renewables
FPVV pricing
Other income
Actual
Lower wholesale prices saw lower realised CFD and merchant
sales and limited ability to generate marginal thermal
generation
Renewable generation slightly above mean (+45GWh)
at expected thermal SRMC
C&I net price of $134/MWh in 1H lower than full year
expectation
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
=
=
=
=
=
=
=
* Fuel is natural gas and carbon costs
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 241GWh for 1H23 assumed
6.Locational losses of 6.7% on spot purchases and settlement
of CFDs sold at a wholesale price of $150/MWh
Fixed costs
Lower thermal volume lower fixed costs for the period
6
28
11
3
280
246
1
1
This includes impact on ASX market making loss
of $12m in the period
Normalised and expected EBITDAF assumptions
1H23 results
With reconciliation to actual performance
x
Gas, carbon, acquired generation price
Gas price favourable
41
FY23FY24FY25FY26FY27FY28FY29FY30FY31FY32FY33FY34
Provision open
-120-121-124-118-115-103-91-77-61-44-26-5
Provision release
13119161718191920215
Interest on unwind
of discount
-3-5-5-5-5-4-4-3-2-2-10
Provision close
-121-124-118-115-103-91-77-61-44-26-50
Onerous contract provision for AGS
Onerous contract treatment for AGS:
•A non-cash accounting adjustment that recognises the
difference between the expected benefits received and
the contracted schedule of payments. The difference is
discounted at the risk-free rate to determine the size of
the provision.
•These schedules (RHS) show the current modelled
impacts to EBITDAF and profit and loss before tax over
the life of the contract.
•Accounting standards require that the provision is tested
for potential restatement in each reporting period.
•This detail is being provided as a one-time illustration
i.e. will not be published every reporting period.
Key assumptions:
•Storage cost:Current annual cost (net of rebate from
3rd party usage) escalated at PPI until the end of the
contract in September 2033.
•Discount rate: Risk free rate of 4.48% (10-year NZ
government bond) has been used as the pre-tax
discount rate, in line with the accounting standard.
Provision –Gas Storage Costs
FY23FY24FY25FY26FY27FY28FY29FY30FY31FY32FY33FY34
Storage cost
-26-28-29-30-31-32-33-34-35-36-37-9
Provision release
13119161718191920215
EBITDAF impact
-25-25-19-21-15-15-15-15-15-15-15-4
Interest on unwind
of discount
355554432210
Profit and loss
before tax
-22-20-13-16-10-11-12-12-13-14-15-4
Profit and loss before tax ($m)
Provision release schedule ($m)
Contact has recognisedan onerous contract provision of $120m ($86m after tax) in 1H23, reflecting the
modelled reduction in gas storage capacity at AGS
---
2 Contact | Interim Financial Statements Contact | Interim Financial Statements 3
About these financial statements
FOR THE SIX MONTHS ENDED 31 DECEMBER 2022
These interim financial statements are for Contact, a group made up of Contact Energy Limited, the entities over which it has
control and its associates.
Contact Energy Limited is registered in New Zealand under the Companies Act 1993. It is listed on the New Zealand stock exchange
(NZX) and the Australian Securities Exchange (ASX) and has bonds listed on the NZX debt market. Contact is an FMC reporting entity
under the Financial Markets Conduct Act 2013.
Contact’s interim financial statements for the six months ended 31 December 2022 provide a summary of Contact’s performance
for the period and outline significant changes to information reported in the financial statements for the year ended 30 June 2022
(2022 Annual Report). The Financial Statements should be read with the 2022 Annual Report.
Contact’s financial statements are prepared:
• in accordance with New Zealand generally accepted accounting practice (GAAP) and comply with NZ IAS 34 Interim Financial
Reporting and IAS 34 Interim Financial Reporting.
• in millions of New Zealand dollars (NZD) unless otherwise noted.
• using the same accounting policies and significant estimates and critical judgments disclosed in the 2022 Annual Report.
• with certain comparative amounts reclassified to conform to the current period’s presentation.
The financial statements were authorised on behalf of the Contact Energy Limited Board of Directors on 10 February 2023:
Robert McDonald Sandra Dodds
Chair Chair, Audit & Risk Committee
Statement of comprehensive income
FOR THE SIX MONTHS ENDED 31 DECEMBER 2022
$m Note
Unaudited
6 months ended
31 Dec 2022
Unaudited
6 months ended
31 Dec 2021
Audited
Year ended
30 June 2022
Revenue A2 994 1,141 2,387
Operating expenses A2 (868) (819) (1,850)
Interest expense B4 (20) (19) (36)
Interest revenue B4 1 - -
Depreciation and amortisation C1 (111) (129) (262)
Change in fair value of financial instruments D1 (6) 13 14
Profit/(loss) before tax *(9) 187 253
Tax expense 2 (53) (71)
Profit/(loss) (7) 134 182
Items that may be reclassified to profit/(loss):
Change in hedge reserves (net of tax) (30) 33 (31)
Comprehensive income (37) 167 151
Profit/(loss) per share (cents) - basic and diluted (0.9) 17.2 23.4
*Profit/(loss) before tax includes an onerous contract provision relating to Ahuroa Gas Storage facility (AGS) of $120 million.
Excluding the onerous contract provision, Profit/(loss) before tax would be $111 million.
4 Contact | Interim Financial Statements
Contact | Interim Financial Statements 5
Statement of cash flows
FOR THE SIX MONTHS ENDED 31 DECEMBER 2022
$m Note
Unaudited
6 months ended
31 Dec 2022
Unaudited
6 months ended
31 Dec 2021
Audited
Year ended
30 June 2022
Receipts from customers 1,023 1,211 2,397
Payments to suppliers and employees (820) (965) (1,880)
Interest paid
(12) (15) (28)
Tax paid (76) (65) (89)
Operating cash flows 115 166 400
Purchase and construction of assets
(272) (151) (347)
Capitalised interest
(17) (8) (19)
Investment in associates
(4) (6) (11)
Proceeds from sale of assets
4 - 1
Deferred consideration for acquisition of subsidiaries (11) (5) (5)
Investing cash flows (300) (170) (381)
Dividends paid B2 (146) (145) (242)
Proceeds from borrowings 643 267 536
Repayment of borrowings (315) (193) (291)
Financing costs
(2) (4) (4)
Financing cash flows
180 (75) (1)
Net cash flow
(5) (79) 18
Add: cash at the beginning of the period
168 150 150
Cash at the end of the period
163 71 168
Statement of financial position
AT 31 DECEMBER 2022
$m Note
Unaudited
31 Dec 2022
Unaudited
31 Dec 2021
Audited
30 June 2022
Cash and cash equivalents 163 71 168
Trade and other receivables 211 186 227
Inventories 39 87 58
Intangible assets C1 72 64 27
Derivative financial instruments D1 59 29 23
Assets held for sale
5 - 5
Total current assets 549 437 508
Property, plant and equipment C1 4,293 4,024 4,095
Intangible assets C1 197 205 200
Goodwill
214 214 214
Inventories C2 36 - -
Investment in associates
24 16 21
Derivative financial instruments D1 95 82 128
Total non-current assets 4,859 4,541 4,658
Total assets 5,408 4,978 5,166
Trade and other payables 252 235 261
Tax payable 1 33 36
Borrowings B3 415 115 287
Derivative financial instruments D1 121 54 98
Provisions 6 14 15
Total current liabilities 795 451 697
Borrowings B3 985 814 812
Derivative financial instruments D1 197 50 128
Provisions *183 53 58
Deferred tax 563 645 616
Other non-current liabilities 26 14 15
Total non-current liabilities 1,953 1,576 1,629
Total liabilities 2,748 2,027 2,326
Net assets 2,660 2,951 2,840
Share capital B1 1,976 1,944 1,955
Retained earnings 788 1,019 958
Hedge reserves (113) (18) (82)
Share-based compensation reserve 9 6 8
Shareholders' equity 2,660 2,951 2,840
*Non-current provisions include an onerous contract provision relating to AGS of $120 million.
6 Contact | Interim Financial Statements
Contact | Interim Financial Statements 7
Statement of changes in equity
FOR THE SIX MONTHS ENDED 31 DECEMBER 2022
$m Note Share capital
Retained
earnings
Other
reserves
Shareholders'
equity
Balance at 1 July 2021 1,922 1,048 (43) 2,927
Profit/(loss) A2 - 134 - 134
Change in hedge reserves (net of tax) - - 33 33
Change in share-based compensation reserve - - (2) (2)
Change in share capital B1 22 - - 22
Dividends paid B2 - (163) - (163)
Unaudited balance at 31 December 2021 1,944 1,019 (12) 2,951
Profit/(loss) A2 - 48 - 48
Change in hedge reserves (net of tax) - - (64) (64)
Change in share-based compensation reserve - - 2 2
Change in share capital B1 11 - - 11
Dividends paid B2 - (109) - (109)
Audited balance at 30 June 2022 1,955 958 (74) 2,840
Profit/(loss) A2 - (7) - (7)
Change in hedge reserves (net of tax) - - (30) (30)
Change in share-based compensation reserve - - - -
Change in share capital B1 21 - - 21
Dividends paid B2 - (164) - (164)
Unaudited balance at 31 December 2022 1,976 788 (104) 2,660
A. Our performance
Notes to the financial statements for the six months ended 31 December 2022
A1. SEGMENTS
Contact reports activities under the Wholesale segment and the Retail segment. There have been no significant changes to
Contact’s operating segments in the current period.
The Wholesale segment includes revenue from the sale of electricity to the wholesale electricity market, to Commercial & Industrial
(C&I) customers, and to the Retail segment, less the cost to generate and/or purchase the electricity and costs to serve and
distribute electricity to C&I customers.
The results of Simply Energy Limited and Western Energy Services Limited are included in the Wholesale segment. The results of
Contact Energy Risk Limited have been allocated across the operating segments based on fixed asset values, revenues, and
headcount.
The Retail segment includes revenue from delivering electricity, natural gas, broadband and other products and services to mass
market customers less the cost of purchasing those products and services, and the cost to serve customers.
‘Unallocated’ includes corporate functions not directly allocated to the operating segments.
The Retail segment purchases electricity from the Wholesale segment at a fixed price in a manner similar to transactions with third
parties.
8 Contact | Interim Financial Statements
Contact | Interim Financial Statements 9
A2. EARNINGS
The table below provides a breakdown of Contact’s revenue, expenses and earnings before interest, tax, depreciation and amortisation and changes in fair value of financial instruments (EBITDAF) by segment, and a reconciliation from EBITDAF to profit/(loss) reported under NZ GAAP.
EBITDAF is used to monitor performance and is a non-GAAP profit measure.
Unaudited 6 months ended 31 Dec 2022 Unaudited 6 months ended 31 Dec 2021 Audited year ended 30 June 2022
$m
Wholesale Retail Unallocated Eliminations Total Wholesale Retail Unallocated Eliminations Total Wholesale Retail Unallocated Eliminations Total
Mass market electricity
- 482 - - 482 - 448 - - 448 - 869 - (1) 868
C&I electricity - fixed price
126 - - - 126 100 - - - 100 215 - - - 215
C&I electricity - pass through
9 - - - 9 15 - - - 15 34 - - - 34
Wholesale electricity, net of hedging
260 - - - 260 476 - - - 476 1,071 - - - 1,071
Electricity-related services revenue
6 - - - 6 4 - - - 4 8 - - - 8
Inter-segment electricity sales
241 - - (241) - 199 - - (199) - 395 - - (395) -
Gas
3 48 - - 51 3 43 - - 46 7 82 - - 89
Steam
19 - - - 19 19 - - - 19 33 - - - 33
Geothermal services
3 - - - 3 1 - - - 1 3 - - - 3
Broadband
- 32 - - 32 - 25 - - 25 - 53 - - 53
Other income
- 6 - - 6 6 3 - - 9 6 7 - - 13
Total revenue
667 568 - (241) 994 821 519 - (199) 1,141 1,772 1,011 - (396) 2,387
Electricity purchases, net of hedging
(204) - - - (204) (318) - - - (318) (793) - - - (793)
Electricity purchases - pass through
(5) - - - (5) (9) - - - (9) (26) - - - (26)
Electricity related services cost
(3) - - - (3) (5) - - - (5) (8) - - - (8)
Inter-segment electricity purchases
- (241) - 241 - - (199) - 199 - - (395) - 395 -
Gas and diesel purchases
(29) (15) - - (44) (42) (18) - - (60) (95) (33) - - (128)
Gas storage costs
*(132) - - - (132) (11) - - - (11) (24) - - - (24)
Carbon emissions costs
(12) (6) - - (18) (13) (3) - - (16) (38) (6) - - (44)
Generation transmission & levies
(14) - - - (14) (9) - - - (9) (24) - - - (24)
Electricity networks, levies & meter costs - fixed price
(32) (218) - - (250) (32) (208) - - (240) (60) (407) - - (467)
Electricity networks, levies & meter costs - pass through
(1) - - - (1) (5) - - - (5) (8) - - - (8)
Gas networks, transmission & meter costs
(3) (24) - - (27) (3) (21) - - (24) (6) (40) - - (46)
Geothermal service costs
(2) - - - (2) (1) - - - (1) (2) - - - (2)
Broadband costs
- (28) - - (28) - (21) - - (21) - (45) - - (45)
Other market costs
(22) - - - (22) (2) - - - (2) (25) - - - (25)
Other operating expenses
(61) (35) (22) - (118) (55) (33) (10) - (98) (115) (68) (28) 1 (210)
Total operating expenses
(520) (567) (22) 241 (868) (505) (503) (10) 199 (819) (1,224) (994) (28) 396 (1,850)
EBITDAF
147 1 (22) - 126 316 16 (10) - 322 548 17 (28) - 537
Depreciation and amortisation
(111)
(129)
(262)
Net interest expense
(19)
(19)
(36)
Change in fair value of financial instruments
(6)
13
14
Tax expense
2
(53)
(71)
Profit/(loss) (7) 134 182
*Gas storage costs include an onerous contract provision relating to AGS of $120 million.
10 Contact | Interim Financial Statements
Contact | Interim Financial Statements 11
A3. FREE CASH FLOW
Free cash flow is a non-GAAP cash measure that shows the amount of cash Contact has available to distribute to shareholders,
reduce debt or reinvest in growing the business. A reconciliation from EBITDAF to NZ GAAP operating cash flows and to free cash
flow is provided below.
$m
Unaudited
6 months ended
31 Dec 2022
Unaudited
6 months ended
31 Dec 2021
Audited
Year ended
30 June 2022
EBITDAF 126 322 537
Tax paid (76) (65) (89)
Change in working capital, net of investing and financing activities (43) (69) (17)
Non-cash items included in EBITDAF 120 (7) (3)
Net interest paid, excluding capitalised interest (12) (15) (28)
Operating cash flows 115 166 400
Stay-in-business capital expenditure (55) (35) (79)
Operating free cash flow 60 131 321
Proceeds from sale of assets 4 - 1
Free cash flow 63 131 322
Operating free cash flow per share (cents) 7.7 16.8 41.8
30 June 2022 stay-in-business capital expense has been restated, increasing by $4 million and therefore also decreasing operating
free cash flow and free cashflow by $4 million. This is a reclassification between stay-in-business capital expense and growth capital
expense, which has no impact on total capital expense.
A4. RELATED PARTY TRANSACTIONS
Contact’s related parties include its Directors, the Leadership Team (LT), Drylandcarbon One Limited Partnership, and Forest
Partners Limited Partnership.
$m
Unaudited
6 months ended
31 Dec 2022
Unaudited
6 months ended
31 Dec 2021
Audited
Year ended
30 June 2022
Drylandcarbon One Limited Partnership
Capital contributions - (6) (9)
Forest Partners Limited Partnership
Capital contributions (4) - (2)
Key management personnel
Directors' fees (1) (1) (1)
LT - salary and other short-term benefits (4) (5) (7)
LT - share-based compensation expense (1) (1) (1)
Members of the Directors and LT purchase goods and services from Contact for domestic purposes on normal commercial terms
and conditions. For members of the LT this includes the staff discount available to all eligible employees. Salary and other short-
term benefits are the cash amount paid in the year.
A5. PROVISIONS
In late 2021 Contact was notified of an unexpected and unexplained increase in pressure recorded in the AGS facility by the owner
and operator, Flexgas, to whom Contact sold the facility in 2018. This suggested that the current storage capacity of the facility was
less than previously thought, which may impact the storage capacity available to Contact. Contact and Flexgas formed a joint
technical working group to investigate these concerns and assess whether there are actions that could be taken to improve the
performance of the facility.
During the six months ended 31 December 2022, the technical working group concluded the first stage of studies into the issues
and Contact has largely concluded its internal review of the findings using an independent technical expert. The technical working
group have found that the estimate of current available storage is between 10 and 12 PJs which is less than originally understood.
Also, to maintain reservoir pressure to support the optimal daily injection and extraction rate, approximately 4PJs of gas currently
stored in AGS ($36m) and owned by Contact may only be available for extraction at the end of Contact’s storage contract in 2033.
Based on the findings, Contact has assessed the storage contract in line with NZ IAS 37 Provisions, Contingent Liabilities and
Contingent Assets and has recognised a new onerous contract provision of $120 million at 31 December 2022.
The provision is calculated as the difference between the contract payments and the value received from access to available AGS
storage over the remaining term of contract, discounted to present value using a pre-tax discount rate of 4.5%.
There is a significant level of judgement involved in estimating the value Contact will obtain from the contract for the remainder of
its term with key drivers such as, hydrology, future gas and carbon prices, the level of Contact’s contracted sales, and the market
supply/demand balance.
If the value received increased by 10%, the provision would reduce by $15 million. If the value received decreased by 10% the
provision would increase by $15 million.
A6. CONTINGENCIES
In the normal course of business, Contact is subject to inquiries, claims and investigations. There are no other material matters to
disclose in this respect at 31 December 2022.
12 Contact | Interim Financial Statements
Contact | Interim Financial Statements 13
B. Our funding
Notes to the financial statements for the six months ended 31 December 2022
B1. SHARE CAPITAL
Number $m
Balance at 1 July 2021 776,122,070 1,922
Share capital issued 3,001,936 22
Balance at 31 December 2021 779,124,006 1,944
Share capital issued 1,514,297 11
Balance at 30 June 2022 780,638,303 1,955
Share capital issued 2,619,193 21
Balance at 31 December 2022 783,257,496 1,976
Comprised of:
Ordinary shares 783,000,347 1,975
Contact Share 257,149 1
During the period Contact granted a new tranche of share awards under the Equity Scheme, comprising 360,281 performance
share rights (PSRs) and 348,226 deferred share rights (DSRs). PSRs and DSRs have no exercise price and have a vesting period of
three years and two years respectively.
B2. DIVIDENDS PAID
$m Cents per share
Unaudited
6 months ended
31 Dec 2022
Unaudited
6 months ended
31 Dec 2021
Audited
Year ended
30 June 2022
2021 final dividend 21 - 163 163
2022 interim dividend 14 - - 109
2022 final dividend 21 164 - -
164 163 272
Comprising:
Cash dividends
146 145 242
Dividend reinvestment plan 18 18 30
On 10 February 2023 the Board declared an interim dividend of 14 cents per share to be paid on 30 March 2023.
B3. BORROWINGS
$m
Unaudited
31 Dec 2022
Unaudited
31 Dec 2021
Audited
30 June 2022
Bank overdraft - 5 2
*Commercial paper 230 - 175
*Drawn bank facilities 139 - 7
Lease obligations 26 24 25
*Retail bonds 350 200 200
*Capital bonds 225 225 225
*Export credit agency facility
36 43 40
*USPP notes
376 376 376
Face value of borrowings 1,382 873 1,050
Deferred financing costs (8) (6) (6)
Fair value adjustment on hedged borrowings 26 62 55
Carrying value of borrowings 1,400 929 1,099
Current 415 115 287
Non-current 985 814 812
$250 million retail bond was issued during the period, with an interest rate of 5.82%, maturing in April 2028.
Borrowings denoted with an asterisk (*) are Green Debt Instruments under Contact’s Green Borrowing Programme, which has
been certified by the Climate Bonds Initiative. At 31 December 2022 Contact remains compliant with the requirements of the
programme. Further information is available on the Sustainability section on Contact’s website.
B4. NET INTEREST EXPENSE
$m
Unaudited
6 months ended
31 Dec 2022
Unaudited
6 months ended
31 Dec 2021
Audited
Year ended
30 June 2022
Interest expense on borrowings (32) (24) (48)
Interest expense on finance leases (1) - (1)
Unwind of discount on provisions (3) (3) (5)
Unwind of deferred financing costs (1) - (1)
Capitalised interest 17 8 19
Interest income 1 - -
Net interest expense (19) (19) (36)
14 Contact | Interim Financial Statements
Contact | Interim Financial Statements 15
C. Our assets
Notes to the financial statements for the six months ended 31 December 2022
C1. PROPERTY, PLANT AND EQUIPMENT AND INTANGIBLE ASSETS
Property, plant and equipment
$m
Unaudited
31 Dec 2022
Unaudited
31 Dec 2021
Audited
30 June 2022
Opening balance 4,095 3,961 3,961
Additions 293 171 359
Acquisitions - - 12
Transfers to assets held for sale - - (17)
Disposals (2) (3) (5)
Depreciation charge (93) (105) (215)
Closing balance 4,293 4,024 4,095
Included within property, plant and equipment is $30 million (31 December 2021: $28 million, 30 June 2022: $29 million) of lease
assets with a depreciation charge of $2 million for the six months ended 31 December 2022 (31 December 2021: $2 million, 30
June 2022: $5 million).
Included within additions is capitalised interest of $17 million (31 December 2021: $8 million, 30 June 2022: $19 million) in
relation to the build of the Tauhara and Te Huka Unit 3 power stations and associated steamfield.
Intangibles
$m
Unaudited
31 Dec 2022
Unaudited
31 Dec 2021
Audited
30 June 2022
Opening balance 227 245 245
Additions 75 67 122
Disposals (15) (19) (92)
Transfers to assets held for sale - - (1)
Amortisation charge (18) (24) (47)
Closing balance 269 269 227
Current 72 64 27
Non-current 197 205 200
At 31 December 2022, Contact was committed to $323 million of contracted capital expenditure (31 December 2021: $263 million,
30 June 2022: $275 million) and $119 million of carbon forward contracts (31 December 2021: $68 million, 30 June 2022: $150
million), of which $352 million (31 December 2021: $236 million, 30 June 2022: $252 million) is due within one year of balance
date.
C2. INVENTORY
During the period, $36 million of inventory gas has been reclassified from current to non-current inventory as this gas is not
expected to be used within 12 months of reporting date.
16 Contact | Interim Financial Statements
Contact | Interim Financial Statements 17
D. Financial risks
Notes to the financial statements for the six months ended 31 December 2022
D1. SUMMARY OF DERIVATIVE FINANCIAL INSTRUMENTS
A summary of derivatives and the impact on Contact’s financial position is provided below grouped by type of hedge relationship. There were no changes in the Group’s valuation processes, valuation techniques, and types of inputs used in the fair value measurements during the
period.
Unaudited at 31 December 2022 Unaudited at 31 December 2021 Audited at 30 June 2022
Fair
value
hedge
Cash flow &
fair value
hedge Cash flow hedge
No hedge
relationship
Fair
value
hedge
Cash flow &
fair value
hedge Cash flow hedge
No hedge
relationship
Fair
value
hedge
Cash flow &
fair value
hedge Cash flow hedge
No hedge
relationship
$m IRS CCIRS IRS
Electricity
price
derivatives
Foreign
exchange
contracts
Electricity
price
derivatives Total IRS CCIRS IRS
Electricity
price
derivatives
Foreign
exchange
contracts
Electricity
price
derivatives Total IRS CCIRS IRS
Electricity
price
derivatives
Foreign
exchange
contracts
Electricity
price
derivatives Total
Carrying value of derivatives - asset - 57 57 4 2 34 154 3 60 14 14 3 17 111 - 75 37 3 3 33 151
Carrying value of derivatives - liability (26) (8) - (207) (3) (74) (318) (2) (3) (26) (51) (2) (21) (104) (16) (5) (4) (154) (5) (42) (226)
Carrying value of hedged borrowings (545) (252) - - - - (797) (347) (437) - - - - (784) (331) (448) - - - - (779)
Fair value adjustments to borrowings 26 (52) - - - - (26) (1) (61) - - - - (62) 16 (71) - - - - (55)
Change in fair value of financial
instruments to profit/(loss) - - 5 - - (11) (6) - - 15 - - (2) 13 - - 24 - - (10) 14
Hedge effectiveness recognised in OCI - (2) 19 (77) (1) - (61) - 2 18 (12) - - 8 - 4 52 (125) (2) - (71)
Initial premium recognised in trade and
other receivables - - - - - (20) (20) - - - - - - - - - - - - - -
Amounts reclassified to profit/(loss) or
balance sheet - - - 26 1 - 27 - - 3 36 - - 39 - - 5 38 - - 43
The cross-currency interest rate swaps (CCIRS) liability arises from the cash flow hedge component.
Included within hedge reserves balance at 31 December 2022 is $14 million relating to close out of electricity price derivatives which will be amortised over the financial year (31 December 2021: nil, 30 June 2022: $10 million).
18 Contact | Interim Financial Statements
Contact | Interim Financial Statements 19
Conclusion
We have reviewed the interim financial statements of Contact
Energy Limited and its subsidiaries (together “the Group”) on
pages 2 to 17 which comprise the statement of financial position
as at 31 December 2022, and the statement of comprehensive
income, statement of changes in equity and statement of cash
flows for the six month period ended on that date, and a summary
of significant accounting policies and other explanatory
information. Based on our review, nothing has come to our
attention that causes us to believe that the accompanying interim
financial statements on pages 2 to 17 of the Group do not present
fairly, in all material respects, the financial position of the Group
as at 31 December 2022, and its financial performance and its
cash flows for the six month period ended on that date, in
accordance with New Zealand Equivalent to International
Accounting Standard 34: Interim Financial Reporting.
This report is made solely to the Company’s shareholders, as a
body. Our review has been undertaken so that we might state to
the Company’s shareholders those matters we are required to
state to them in a review report and for no other purpose. To the
fullest extent permitted by law, we do not accept or assume
responsibility to anyone other than the Company and the
Company’s shareholders as a body, for our review procedures, for
this report, or for the conclusion we have formed.
Basis for conclusion
We conducted our review in accordance with NZ SRE 2410
(Revised) Review of Financial Statements Performed by the
Independent Auditor of the Entity. Our responsibilities are further
described in the Auditor’s responsibilities for the review of the
financial statements section of our report. We are independent of
the Group in accordance with the relevant ethical requirements in
New Zealand relating to the audit of the annual financial
statements, and we have fulfilled our other ethical responsibilities
in accordance with these ethical requirements.
Ernst & Young provides services to the Group in relation to trustee
reporting, market remuneration surveys, immigration services,
research and development tax credit advice and other assurance
relating to sustainable finance framework. Partners and
employees of our firm may deal with the Group on normal terms
within the ordinary course of trading activities of the business of
the Group. We have no other relationship with, or interest in, the
Group.
Directors’ responsibility for the interim financial
statements
The directors are responsible, on behalf of the Company, for the
preparation and fair presentation of the interim financial
statements in accordance with New Zealand Equivalent to
International Accounting Standard 34: Interim Financial Reporting
and for such internal control as the directors determine is
necessary to enable the preparation and fair presentation of the
interim financial statements that are free from material
misstatement, whether due to fraud or error.
Auditor’s responsibilities for the review of the interim
financial statements
Our responsibility is to express a conclusion on the interim
financial statements based on our review. NZ SRE 2410 (Revised)
requires us to conclude whether anything has come to our
attention that causes us to believe that the interim financial
statements, taken as a whole, are not prepared in all material
respects, in accordance with New Zealand Equivalent to
International Accounting Standard 34: Interim Financial Reporting.
A review of interim financial statements in accordance with NZ
SRE 2410 (Revised) is a limited assurance engagement. We
perform procedures, consisting of making enquiries, primarily of
persons responsible for financial and accounting matters, and
applying analytical and other review procedures. The procedures
performed in a review are substantially less than those performed
in an audit conducted in accordance with International Standards
on Auditing (New Zealand) and consequently do not enable us to
obtain assurance that we would become aware of all significant
matters that might be identified in an audit. Accordingly, we do
not express an audit opinion on those interim financial
statements.
The engagement partner on the review resulting in this
independent auditor’s review report is Grant Taylor.
Chartered Accountants
Wellington
10 February 2023
Corporate directory
Board of Directors
Robert McDonald (Chair)
Victoria Crone
Sandra Dodds
Jon Macdonald
David Smol
Rukumoana Schaafhausen
Elena Trout
Leadership team
Mike Fuge
Chief Executive Officer
Chris Abbott
Chief Corporate Affairs Officer
Jack Ariel
Major Projects Director
Jan Bibby
Chief People & Transformation Officer
Matt Bolton
Chief Retail Officer
John Clark
Chief Generation Officer
Dorian Devers
Chief Financial Officer
Iain Gauld
Chief Information Officer
Jacqui Nelson
Chief Development Officer
Tighe Wall
Chief Digital Officer
Registered office
Contact Energy Limited
Harbour City Tower
29 Brandon Street
Wellington 6011
New Zealand
T +64 4 499 4001
Find us on Facebook, Twitter, LinkedIn and Youtube by
searching for Contact Energy
Company numbers
NZ Incorporation 660760
ABN 68 080 480 477
Auditor
Ernst & Young
40 Bowen Street
PO Box 490
Wellington 6011
Company secretary
Kirsten Clayton
General Counsel and Company Secretary
Registry
Change of address, payment instructions and investment
portfolios can be viewed and updated online:
investorcentre.linkmarketservices.co.nz
investorcentre.linkmarketservices.com.au
New Zealand Registry
Link Market Services Limited
PO Box 91976, Auckland 1142
Level 30, PWC Tower
15 Custom Street West, Auckland 1010
contactenergy@linkmarketservices.co.nz
T +64 9 375 5998
Australian Registry
Link Market Services Limited
Locked Bag A14, Sydney
South, NSW 1235
680 George Street, Sydney, NSW 2000
contactenergy@linkmarketservices.com.au
T +61 2 8280 7111
Investor relation enquiries
Shelley Hollingsworth
Investor Relations & Strategy Manager
investor.centre@contactenergy.co.nz
Sustainability enquiries
Taria Tahana
Head of Sustainability
sustainability@contactenergy.co.nz
To the shareholders of Contact Energy Limited
Report on the interim financial statements
Independent Auditor’s review report
---
Results announcement
Results for announcement to the market
Name of issuer Contact Energy Limited
Reporting Period 6 months to 31 December 2022
Previous Reporting Period 6 months to 31 December 2021
Currency NZD
Amount (000s) Percentage change
Revenue from continuing
operations
$994,000 -12.9%
Total Revenue $994,000 -12.9%
Net profit/(loss) from
continuing operations
($7,000) -105.2%
Total net profit/(loss) ($7,000) -105.2%
Interim/Final Dividend
Amount per Quoted Equity
Security
$ 0.14000000
Imputed amount per Quoted
Equity Security
$ 0.04666667
Record Date 10/03/2023
Dividend Payment Date 30/03/2023
Current period Prior comparable period
Net tangible assets per
Quoted Equity Security
$2.78 $3.17
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
13/02/2023
Unaudited 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 Quarterly
Half Year X Special
DRP applies X
Record date 10/03/2023
Ex-Date (one business day before the
Record Date)
09/03/2023
Payment date (and allotment date for
DRP)
30/03/2023
Total monies associated with the
distribution
$109,656,049
(783,257,496 shares @ $0.14 / share)
Source of distribution (for example,
retained earnings)
Operating Free Cash Flow
Currency NZD
Section 2: Distribution amounts per financial product
Gross distribution $ 0.18666667
Gross taxable amount $ 0.18666667
Total cash distribution $ 0.14000000
Excluded amount (applicable to listed
PIEs)
N/A
Supplementary distribution amount $ 0.02117647
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
$ 0.04666667
Resident Withholding Tax per
financial product
$ 0.01493333
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
09/03/2023 15/03/2023
Date strike price to be announced (if
not available at this time)
16/03/2023
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
13/03/2023
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
13/02/2023
Data sourced from publicly available filings. Our datasets may not be complete. Automated analysis can produce errors. If you believe any data on this page is incorrect, please contact us at hello@nzxplorer.co.nz. For informational purposes only. Not investment advice.
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