Contact Energy FY22 Interim Result
contactenergy.co.nz
NZX release: 14 February 2022: Contact Energy FY22 Interim Result
Strong performance underpins Contact’s ramp-up of
investment in NZ’s decarbonisation
Key financial metrics
Six months ended
31 December 2021
1H 22
Six months ended
31 December 2020
1H 21
EBITDAF
1
$322m ↑ 31% from $246m
Profit $134m ↑ 72% from $78m
Interim dividend per share 14.0 cps - no change
Operating free cash flow
2
$131m ↓ 17% from $157m
Stay-in-business capital expenditure $35m ↑ 13% from $31m
Growth capital expenditure $116m ↑ 2220% from $5m
Highlights
• Solid financial performance, with operating earnings and profit up off the back of strong
hydro generation and increased sales to fuel-constrained competitors;
• Decarbonisation-driven investments ramping up, supported by long-term power
purchase agreements;
• Good progress on the Tauhara geothermal project despite COVID19-related headwinds,
with the power station’s expected capacity upgraded to 168MW, and the potential
Tauhara geothermal field output upgraded by a further 0.2TWh p.a.;
• Applications lodged for an extension of geothermal consents at Wairakei post-2026 and
a potential 50MW geothermal power station at Te Huka in the Taupō region;
• Secured land access rights for ~600MW of wind projects across New Zealand through
our exclusive relationship with wind generation experts Roaring40s;
• Intention to invest a further $37m into a new afforestation partnership to support further
carbon capture through tree planting;
• Launched ‘It’s good to be home’ brand campaign, with new ‘Good Nights’ pricing plan
resonating with customers; total connections increased by 29,000 in the first half of
FY22;
• Interim cash dividend of 14 cents per share will be paid on 30 March 2022.
1
Refer to slide 39 of the 2022 interim results presentation for a definition and reconciliation between statutory profit and the non-GAAP profit measures earnings before
net interest expense, tax, depreciation, amortisation, change in fair value of financial instruments (EBITDAF)
2
Refer to note A3 of the 2022 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
New Zealand renewable energy company Contact Energy (‘Contact’) released its interim
financial results for the six months to 31 December 2021 today.
Contact CEO Mike Fuge said the company had delivered a “solid financial performance” in
the first half of the FY22 financial year and was investing in line with its strategy to lead New
Zealand’s decarbonisation efforts.
Financial performance
Contact reported a statutory profit of $134m, up 72 per cent ($56m) on the same period last
year. Operating earnings (EBITDAF) increased by $76m to $322m, up 31 per cent on the
prior year. Operating free cash flow for the period decreased from $157m to $131m in the
first six months of FY22, down 17 per cent year-on-year.
Mr Fuge said: “It’s very pleasing to provide investors with a solid financial report card. We’ve
seen double-digit growth in our operating earnings and profit off the back of a period of
strong hydro generation.
“While operating free cash flow is lower year-on-year, this is a feature of our generation
asset mix. When it rains, operating earnings increase as we don’t have to run more
expensive thermal generation, but cash flow is impacted as we store the gas we purchased
for use in the future.
“We’ve also progressed a range of renewable energy projects across New Zealand and our
retail business has continued to build market share in electricity and broadband.”
The Board has approved an interim dividend of 14 cents per share and this will be imputed
up to 10 cents per share for qualifying shareholders and paid on 30 March 2022.
Demand
In line with Contact’s decarbonisation focus, Mr Fuge said there had been strong demand for
renewable electricity from forward-thinking customers.
“We’re delighted to have secured long-term power purchase agreements with Oji Fibre, Pan
Pac, Genesis Energy and Foodstuffs. Long-term contracts underpin sustainable operations,
support additional renewable generation development, and can also displace thermal
generation. These agreements will reduce carbon emissions and help keep electricity prices
down over the long-term.”
The Southern Green Hydrogen project to investigate the world’s first large-scale green
hydrogen plant in Southland with Meridian Energy is also progressing well. Potential
development partners have been shortlisted and are engaged in a formal ‘request for
proposal’ process.
Rio Tinto has recently indicated a desire to continue operating its unique low carbon smelter
at Tiwai Point beyond 2024, when the current electricity supply contract concludes.
“It’s early days, but we are encouraged that the smelter’s owner recognises it needs to play
a larger role to help manage dry year security of supply in New Zealand’s electricity system,”
Mr Fuge said. “In turn, this will lower system carbon emissions and enable the development
of more renewable generation, which is positive for New Zealand.”
contactenergy.co.nz
Renewable development
On the renewable development front, the Tauhara power station’s expected capacity has
recently been upgraded from 152MW to 168MW. It is now expected to be completed in the
second half of 2023, with an increase in the estimated costs of the project.
“We have encountered some COVID19-related headwinds, but overall the project remains
on track. It will be a world-class renewable development that will be a foundation for New
Zealand’s increased renewable electricity needs over the next decade,” Mr Fuge said.
Consent applications have also been lodged with the Waikato Regional Council for an
extension of the geothermal consents at Wairakei post-2026, and land use consents have
been lodged for a new 50MW geothermal power station development at Te Huka, near
Taupō.
Contact has also secured land access rights to build up to 600MW of wind projects across
New Zealand, via its exclusive relationship with wind generation experts Roaring40s. And
separately, an investigation is under way into the economics of a 100MW battery energy
storage system investment.
Retail
Mr Fuge said there were encouraging results from Contact’s retail business over the first half
of the FY22 year. “We’ve seen total connections increase by 29,000 across electricity and
broadband. A new time-of-use plan, ‘Good Nights’, was launched and has proven very
popular with customers who are keen to have three hours of free power every night from
9pm.”
A new brand campaign launched in January, focused on the idea that ‘home is the best
place in the world’, provides Contact with a platform to grow its commitments to the
community, environment, and people.
Outlook
Looking ahead, Mr Fuge said Contact was committed to leading the decarbonisation of New
Zealand. “We are excited about the critical role that Contact’s renewable electricity generation
is set to play in the decarbonisation of the New Zealand economy over the next decade.”
-ends-
MORE INFORMATION
1/ Enquiries
Investors
Matt Forbes, matthew.forbes@contactenergy.co.nz, +64 21 072 8578
Media
Leah Chamberlin-Gunn, leah.chamberlin-gunn@contactenergy.co.nz, Ph +64 21 2277991
2/ Conference call
A conference call to support the interim results announcement will be held at 10am, NZ time
on 14 February 2022.
contactenergy.co.nz
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
---
2022 interim results
presentation
Six months ended 31 December 2021
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 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.
3
1H22 highlights and market update / Mike Fuge, CEO4 -13
Financial results and outlook / Dorian Devers, CFO 14 -30
Supporting materials 31 -43
2
3
1
Agenda
4
1H22
performance
highlights
Mike Fuge, CEO
5
1
Refer to slides 39 for a definition and reconciliation of EBITDAF
2
Refer to slides 25 for a reconciliation of operating free cash flow
Six months ended
31 December 2021
(1H22)
Six months ended
31 December 2020 (1H21)
EBITDAF
1
$322m↑31% from $246m
Profit$134m↑72% from $78m
Profit per share17.2 cps↑58% from 10.9cps
Operating free cash flow
2
$131m↓17% from $157m
Operating free cash flow per share
2
16.8 cps↓23% from 21.9cps
Interim dividend declared$109m→$109m
Interim dividend declared per share14.0 cps→14.0 cps
Stay-in-business(SIB)capital
expenditure (cash)
$35m↑13% from $31m
Growth capital expenditure (cash)$116m↑2,220% from $5m
Strategic investments (cash)$12m↑71% from $7m
The operating conditions in 1H22 were
characterised by:
•Strong Clutha hydro flows, followed by
improving national hydro storage in the
second quarter of FY22.
•Improved deliverability outlook for the Maui
and Kupe gas fields.
•Falling wholesale spot prices.
•Material increases to gas and carbon costs.
•Elevated wholesale electricity futures as
thermal costs rise and as gas uncertainty
persists.
Summary of key financial performance measures
Strong performance despite volatile market
conditions, investment ramps up
Contact responded to the conditions by:
•Supporting the market with our diverse
portfolio of assets.
•Increasing renewable generation and stored
fuel for future use.
•Long-term offtake agreements signed.
•Investment programme to deliver on
decarbonisation strategy ramping up.
Operating earnings (EBITDAF) were up by
$76m when compared to 1H21.
1H22 market
6
Key strategic highlights from 1H22
Tauhara project progressing well despite
COVID impacts. Renewable capacity up by
11% to 168MW.
Consent applications lodged with Waikato
Regional Council for an extension of
consents at Wairakei post 2026.
Land use consent applications lodged in
December 2021 for a potential 50MW
geothermal station at TeHuka.
Secured land access rights for ~600MW of
wind projects across New Zealand through
our Roaring40s partnership.
Intention to invest a further $37m into
a new afforestation partnership.
‘ThermalCo’ concept released to
stimulate constructive engagement
from key stakeholders.
Progress on the assessment of the
economics of a 100MW battery
energy storage system. Target FY22
investment decision.
Positive long-term outlook for a
renewables backed smelter.
Consent application for aContact-backed
10MW Clyde data centre submitted. Final
consent hearing pending.
Southern Green Hydrogen registration of
interest completed. Preferred parties will
be selected soon for formal proposal in
April 2022. Dry year flexibility concept
accepted.
Agreed terms for PPAs with Genesis
Energy, Oji Fibre, Pan Pac and
Foodstuffs.
Objective
1H22
highlights
Attract new industrial
demand with globally
competitive renewables
Build renewable generation
and flexibility on the back
of new demand
Lead an orderly
transition to
renewables
Create NZ's leading energy
and services brand to meet
more of our customers’ needs
Grow
demand
Grow renewable
development
Decarbonise
our portfolio
Create outstanding
customer experiences
Investing ~$30m in the upgrade of our core SAP
system to S4HANA
Improved brand and experience metrics
demonstrated by an improvement in ‘Brand Trust’
ranking up 1 to #3 and NPS up 2.7 on prior year.
Protected mass market customers from high
wholesale prices –electricity tariff up 1.2% (vs CPI
of 5.9%).
Total connections up by 29k in the 6 months.
Broadband up 11k. Energy up 18k. Customers lost
(churn) down by 2.4% on 1H21.
Successful launch of ‘Good Nights’ –a pilot
time-of-use plan
7
Strong operational performance with high plant
availability. Geothermal availability of 96%, the
highest in 5 years. TCC availability at 100%.
Completion of geothermal optimisation projects
resulting in an increase of 6MW of output
(equivalent to ~25GWh p.a.).
Geothermal fluid process optimisation of consent,
steamfieldand capacity saw more generation at
higher prices with geothermal GWAP/TWAP at
101% ($3m benefit).
Invested in new digital capability to increase focus
on advanced analytics, process optimisation,
redesign and automation.
Completed a$225m issuance of green capital bonds to
retail and institutional investors.The bonds are NZs
first certified green capital bonds.
Reporting of key ESG metrics in our monthly operating
reports. Elevating the priority of our ESG reporting
alongside our financial reporting.
•Scope 1 emissions from generation: 346,000
tCO2e, a 34% reduction on the same period the
previous year.
•47,259 natives planted
•2,727 pests caught
Improved on DJSI ranking to 78th percentile (2020: 62
percentile 2019: 55 percentile).
.
Create long-term value through our strong
performance across a broad set of environmental,
social and governance factors
Continuously improving our operations
through innovation and digitisation
Create a flexible and high-performing
environment for NZ's top talent
Our ESG
commitment
Operational
excellence
Transformative
ways of working
Launched a new learning platform ‘Contact
University’ to grow capability with on-demand
learning.
Secured ‘right-sized’ tenancies in Wellington and
Auckland to reflect the working preferences of our
people.
Committed to become a founding partner of the
Wellbeing Tick –an accredited framework to focus
on enhanced wellbeing of our people.
Objective
1H22
highlights
Key strategic highlights from 1H22
8
(2%)
1%
2%
5%
(11%)
(13%)
(1%)
(0%)
0%
0%
(1%)
(2%)
National electricity demand
Source: EMI, Contact.
Does not include NZAS
National electricity demand (TWh)
Regional
change (%)
1H22 vs 1H21
Source: EMI, Contact
Market demand
(2%)
2%
(2%)
(1%)
4%
2.52.5
2.62.6
2.5
2.5
5.0
5.3
5.0
5.3
5.4
5.2
13.3
13.4
13.4
13.5
13.4
13.3
21.0
21.2
1H17
North Island
1H181H211H191H221H20
South Island (ex NZAS)
NZAS
20.8
21.4
21.3
21.1
1%
-1%
2%
Electricity demand lower than 1H21
Total national electricity demand
decreased by 0.2TWh (-1% from 1H21):
•Demand from large industrial users
was down by 0.2TWh, largely as a
result of the closure of Norske Skog
in June 2021.
•Residential demand increased by
0.3TWh (5%) on increased ICPs and
usage per connectionas a result of
COVID lockdowns and increased
working from home.
•Small business demand was
impacted by extensive Auckland
region lockdowns (-0.2TWh).
•Wet first half of the year saw lower
irrigation demand at major South
Island irrigation demand nodes (-
0.1TWh).
9
Hydro generation was up
6% when compared to
1H21, with above mean
national inflows for the
majority of 1H22.
Investment in the Maui
and Kupe gas fields has
improved the gas
production outlook.
Pohokura production
outlook remains
uncertain.
Generation by type (TWh)
Generation from generator retailers
Lake levels were appropriately managed through the period to manage the risk around gas availability and expected La Nina
conditions in 2022.
Source: EMI & MBIE
Source: NZX
1.7
1.7
2.2
1.0
1.0
0.9
3.6
3.5
3.6
12.7
12.2
12.9
1.0
2.7
2.9
2.1
0.7
1H20
0.4
1H221H21
Gas
Coal
Hydro
Geothermal
Wind
Non grid generation
22.4
22.3
22.1
2.5
0.0
1.0
0.5
4.0
3.5
1.5
2.0
3.0
Dec
2021
Jul
2020
Jan
2021
Jun
2021
Mean
Actual
1H21
1H22
Storage
TWh
National hydro storage
2.32.91.7*
Carbon emissions (mT)
*Carbon emissions for 1H22 Sep-Dec quarter has been estimated using historic conversion rates with actual generation data. The reduction in carbon emissions of 1.2mT CO2-e was due to the decrease in coal and gas generation
Some generation has been estimated based on prior period operation,
Hydrology and impact on generation mix
Fuel supply
Improvedhydro inflows and generation in 1H22 saw a reduced reliance on gas and coal
10
Longer-term the market is reacting to these price signals and adding new capacity
Aluminium
Short-term external factors that
can influence the market
Changes as at 31 December 2021,
in comparison to December 2020
Wholesale and futures electricity pricing ($/MWh)
Source: EMI wholesale pricing
Short-term
wholesale
electricity
prices
Increasing energy input costs are impacting medium-term pricing.
Long-term pricing is linked to the long-run marginal costs of new renewable projects
plus costs associated with firming renewable intermittency to meet growing demand.
Both long-dated and short-dated prices remain well above long-term averages, reflecting
higher thermal fuel costs and the risk around the availability of hydro and thermal fuel. $2bn
of generation investment currently under construction expected to be onstream in 2023/2024
is reducing outer-year futures pricing.
Gas availability -Pohokura
production continues to decline.
Maui and Kupe interventions
appear more sustainable
Carbon prices up 81% to
$68.12/NZU
Methanol pricing
up by $0.85/GJ
gas equivalent
(14% increase)
Limited impact on demand from
COVID. Demand has been
consistent
Aluminium prices sharply higher (+$1,364/t,
up 50%). 4
th
potline reinstatement appears
economic
Coal prices increasing
+$136/t (122%)
0
50
100
150
200
250
300
Jun-
16
Jun-
14
Jun-
11
Jun-
15
Jun-
18
Jun-
12
Jun-
13
Jun-
17
Jun-
19
Jun-
20
Jun-
21
10 year
average
spot price =
$91/MWh
Monthly average spot price
Short-dated futures (<12 months)
Long-dated futures (>12 months)
Long-run prices below LRMC of new generation
Factors that influence short-term prices, beyond
hydrology, sharply higher over last 12 months
Fuel supply and near-term price impact
11
•Competition remains intense, not only from new and disruptive
competitors, but reinvigorated incumbents
•Increase of connections from the main players (+14k connections), Tier
2 market share now at 16% (from 14% 12 months ago)
Change in customer connections (000s)
2yr % change2yr ICP delta (1000s)
Retail tariff changes (c/ kWh)
Tier 2: +51k customers
•Despite sharply higher wholesale prices over the last three years, tariffs up
by a compound annual growth rate of only 2%.
•Households have been largely insulated from higher wholesale prices
because of fixed price residential contracts and retailers’ longer-term view of
pricing that rides through short-term volatility.
•The real residential cost per unit of electricity has fallen in every year since
2018.
12 months
ended:
Tier 1: +14k customers
Source: EMI
Source: MBIE
-4%
4%
14%
0%
9%
9%
4%
26%
42%
-35%
-40
-30
-20
-10
0
10
20
30
40
50
PulseGenesisTrustpowerMercuryContact
-8%
MeridianNovaFlickElectric
Kiwi
VocusOther
17.1
17.4
18.1
19.4
20.1
12.2
12.3
12.1
11.1
11.3
Nov-17Nov-20Nov-18Nov-19Nov-21
29.3
29.7
30.2
30.5
31.5
+2%
Energy & Other (c/kWh)
Lines (c/kWh)
Retail competition remains intense
Retail electricity market
Retailer’s long-term view of pricing rides through short-term wholesale input cost volatility
12
Topical regulatory matters
Gas availability and lower mean water levels through
2021 have resulted in higher spot and hedge market
prices, increasing pressure on unhedged energy
intensive industries.
The Electricity Authority continues to review
wholesale electricity market competition for the
period 2019-21. Its draft analysis finds that prices
have generally reflected underlying supply and
demand conditions, however NZAS may be paying
below the opportunity cost for energy.
Wholesale
market
volatility
Contactis exploring further renewable generation opportunities across wind, solar
and grid-scale batteries to reduce future impacts from thermal fuel volatility .
Contactis working with customers to smooth out pricing volatility through long-term
contracts.
Contacthas submitted to the Electricity Authority that the market is operating
effectively and responding appropriately to recent market volatility, with the sector now
entering a period of intense investment to both decarboniseexisting generation and
new generation to meet future demand.
In June 2021, the Commission delivered its final
report on carbon budgets and policy
recommendations. The government has extended the
publishing of its Emissions Reduction Plan to mid-
2022.
Climate Change
Commission
Contactstrongly supports the recommended direction of the Commission report, and the
role that the energy sector will play in decarbonisation.
Contactcontinues to closely engage in the government’s work and assess the strategic
opportunities and impacts for Contact.
Contacthas released its ThermalCoproposal to accelerate decarbonisationof electricity
generation in support of 100% renewable generation target.
Key themes
What Contact is doing
13
New Zealand
Battery
project
Energy
hardship
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.
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.
Contacthas released its proposal to create a ThermalCowhich would be a low capital, low cost
and low risk solution to accelerate decarbonisation.
Contactis actively engaging with government in to improve theoutcomesforNewZealand.
Covid-19 and the broader economic environment
are placing additional pressure on New Zealand
households and businesses. Contact is actively
working to minimiseenergy hardship.
The Government has established two specialist
energy hardship panels to support work to
alleviate energy hardship in New Zealand.
Contact’stikanga, pricing principles and proactive work with its customers who are struggling to
pay their bills has resulted in reduced disconnections and bad debt.
Contactoffers a range of payment options including weekly and fortnightly billing, pre-pay and
price smoothing products.
Contactis working with industry through ERANZ on the EnergyMateprogrammeand
PowerCreditsscheme in association with budget advisors and FinCap.
Topical regulatory matters
Key themes
What Contact is doing
14
Operational
performance
and financial
results
Dorian Devers, CFO
15
Key themes from the financial results
Financial performance
largely as guidedwhen
higher renewable generation
volumes are considered
Positive view on decarbonisation
demand, including the ability to
retain major electricity users
Innovative retail products
launched to encourage
demand shifting
Cost to serve
remains industry
leading
Signed a number of
long-term PPAs in line
with strategy
Sales channel choices
delivering value
16
Profit ($m)
EBITDAF up $76m, as Contact supported the wholesale market as competitors faced fuel uncertainty
Profit of $134m, up $56m
EBITDAF ($m)
Higher gas
and carbon
costs to
run thermal
generation
Improved net
pricing from
contracted
customers
Higher hydro
generation with
above mean
inflows.
Geothermal
generation in
1H21 impacted
by outages
Active channel
management with
increased sales to
support fuel
constrained market
participants at a
higher price
Higher other
income
(Western
Energy and
Broadband),
and lower gas
and electricity
transmission
costs
54321
1H22 results
1H21 profit
Net interest
costs
EBITDAFDepreciation
& Amortisation
Tax
Fair value of
financial
instruments
1H22 profit
Wholesale
channel
management
Contracted
sales
pricing
1H21
EBITDAF
Renewables
Gas
and
carbon
costs
Other
income,
fixed costs
1H22
EBITDAF
78
134
76
15
21
9
7
+56
43
18
322
6
34
11
246
+76
17
Wholesale EBITDAF ($m)
Retail EBITDAF ($m)
Corporate / unallocated costs ($m)
Business performance by segment
EBITDAF up by $76m
Refer to slides 18 -20
Refer to slide 21
229
316
25
89
28
Total
contracted
revenue
1H22Generation
costs
(including
acquired
generation)
1H21Trading,
merchant
revenue
and losses
+86
30
16
21
2
5
Other
products*
1H21Electricity
volumes
1H22
0
Electricity
prices
0
Opex
-14
Electricity gross margin
(-$16m)
Electricity,
network
cost inflation
Price recovery
*Other products includes retail gas
and broadband gross margins
Simply and Western included within
Wholesale EBITDAF
1H22 results
-13
-10
1
1H21
6
ICT
alignment
One-offsCost
inflation
2
1H22
+3
ICT costs previously included within the Retail business operating
costs. Prior year not restated. Full year impact $3m.
One-offs include the Holidays Act provision reversal ($6.8m) and
Contact SaaS asset write off.
18
Electricity generated or acquired (GWh)
Costs down $25m ($5.4/MWh) on higher renewable generation, which reduced thermal volumes
1H211H22
Electricity generated or acquired costs ($m)
Generation costs
1H22 results: Wholesale business
Gas and diesel
Acquired
Thermal
Renewable
Gas storage
Carbon costs
Electricity and gas
transmission and levies
Other operating costs
Hydro generation up 407GWh on 1H21 (+20%),
401GWh (+20%) above mean year expectations.
Geothermal volumes were 135GWh up on prior year
which had the 4-yearly TeMihi outage.
•Renewable generation costs were down $2m on
1H21. Transmission costs in 1H21 included the
one-off contribution to the CUWLP transmission
upgrade.
Thermal generation costs were down by $26m (29%)
on lower thermal volumes (down 56%).
•Thermal fuel costs up from $79/MWh in 1H21 to
$121/MWh (+53%). With gas (1H21 $7.2/GJ,
1H22 $9.2/GJ) and carbon prices (1H21 $29/unit,
1H22 $34/unit) higher.
•Thermal fixed costs were down by $4m on the
prior comparative period on higher ACOT
revenue and changes to the TCC gas
transmission contract.
Acquired generation costs up by $3m as higher
priced hedges were purchased to support Contact’s
Winter 2021 risk exposures.
1,524
1,659
1,984
2,391
918
407
189
162
1H211H22
4,615
Thermal
Acquired
4,620
Hydro
Geothermal
53
46
51
47
98
18
72
12
22
59
25
40
16
12
12
11
22
25
Cost
type
Generation
type
Cost
type
Generation
type
173173
149149
-25
*Thermal includes tolling of ~10GWh in 1H21 and 0GWh 1H22
79%
Renewable % of
own generation
91%
19
1,928GWh
$103.1/MWh
Contracted
revenue ($m)
Sales mix adjusted to reflect the uncertainty of fuel availability
1,256GWh
$139.5/MWh
-31GWh
+$9.8/MWh
+412GWh
+$42.6/MWh
•Fixed price variable volume electricity sales to the Retail segment and C&I
customers ended 368GWh lower than 1H21 (-$33m), this was offset by higher
prices (+$27m), reflecting higher wholesale prices over the three preceding
years.
•Strategic fixed price sales were 117GWh higher than 1H21 (+7m), lower NZAS
pricing was partially offset by an increase in sales to customersunder long-term
PPAs (-$4m).
•CFD sales volumes were up by 412GWh (+$40m) as nearer term higher priced
channels were prioritised at higher average prices (+$54m).
•Steam revenue was up $2m on 1H21 with steam tariffs on TeRapa generation
rising with carbon costs changes.
•Operating costs to support commercial and industrial customers higher as
capability added to support decarbonisation and a closer customer relationship.
•Other income was in line with the prior year.
Wholesale contracted revenue
24
490GWh
$96.0/MWh
-337GWh
+$11.5/MWh
183
199
70
47
82
175
31
34
17
19
C&I channel
and decarbonisation
support costs
Strategic Fixed Price sales
-6
Retail
segment sales
2
-4
Other net income
1H21
2
1H22
Steam sales
CFD sales
C&I net price
380
469
+89
1H22 results: Wholesale business
625GWh
$54.6/MWh
117GWh
-$6.5/MWh
Year-on-year
changes to
volume and price
1H22 volumes
and price
20
Trading EBITDAF ($m)Long / short position (GWh)
$117.1/MWh
6.8%
($8.0 / MWh)
8.6%
($8.9/ MWh)
•157GWh decrease in
merchant sales volumes.
The price received for
this “long” generation
was down by $13.5/MWh
on 1H21.
•Inter-island separation
increased from 7% to
9%, this was partially
offset by lower absolute
prices. The cost of
generation losses
increased by $5m.
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
$103.6/MWh
Spot purchases and sell
CFD settlement
Spot sales and buy CFD
settlement
Merchant generation
56
33
-33
-38
23
1H211H22
-5
476
320
-4,253
4,253
320
4,091
-4,091
1H211H22
476
1H22 results: Wholesale business
LWAP/GWAP
losses
21
kTof C02e emitted
Lower carbon emissions reflects higher renewable generation and lower thermal generation
Performance
•Total emissions are 161 kTlower in 1H22.
•Emissions from generation was lower in 1H22 as a result of higher
hydro generation volumes.
•Scope 3 emissions have increased year-on-year due to the Tauhara
construction build.
Greenhouse gas reporting
24
178
138
176
527
525
326
1H221H20
1
1
1H21
1
Scope 1
Scope 2
Scope 3*
706
664
503
1H22 results: Carbon performance
*Scope 3 emissions excluding swaption and gas have been estimated using FY21
numbers as this information is collected on an annual basis.
22
Retail business performance
EBITDAF ($m)
Managing through elevated wholesale input costs
The electricity tariff changes balance the
recovery of rising input costs, the
competitive environment and regulatory
pressures:
•68% of our residential customers are
on non-PPD products from January
2022.
•Around 55% of customers received a
price increase in the last 12 months.
•Ending Prompt Payment Discounts
42% reduction in PPD not taken.
Continue to smooth the impact of higher
energy costs for customers:
•Targeted retail price rises to recover
long-run input costs
•Gas tariffs up 10% on 1H21 on
sharply higher gas and carbon input
costs
Strong growth in Broadband connections
(+23k up on 1H21).
Revenue & Tariff
1
($m)
1H211H22Variance
$m$mTariff$mTariff%
Electricity gross
revenue
445.7
449.5249.83.83.9
1.6%
PPD not taken
3.11.8-1.3
Incentives paid
-2.3-2.7-0.4
Net revenue (cash)
446.5448.6249.32.13.01.2%
Capitalisedincentives
3.33.0-0.3
Amortisedincentives
-4.0-3.90.1
Net revenue (P&L)
445.8447.7248.81.93.01.2%
Gas revenue
41.343.427.12.12.59.7%
Broadband revenue
13.024.871.811.83.3
2
4.9%
Other income
2.63.10.5
Total revenue
502.6
519.016.3
Contract Asset
(closing)
8.56.2-2.3
1.Tariff is $/MWh for electricity, Gas $/GJ and $ per month per customer connection for broadband
2.1H21 tariff ($/customer/month) restated to include accounting adjustments that were not made in FY22
to understand broadband tariff progression
57
4
5
41
3
3
-33
-33
Broadband GM
-2
Electricity GM
1H21
30
1
1H22
Gas GM
Other operating
expenses
16
Other income
Gross Margin (GM) is Revenue less Cost of Goods [Networks,
meters, levies, energy, carbon and broadband]
1H22 results: Retail business
Ave. number of
connections ($k)
506.8540.1+33.36.5%
Cost to serve per
connection ($/conn)
66.061.5-4.5-6.8%
23
Other operating
cost movement
($m)
Portfolio, performance and non-recurring
Underlying
movement
Other operating costs
•All costs associated with meters are now reflected in
Cost of Goods (Network, Meters and Levies) to align
with industry reporting. Previously a portion of smart
meter costs were included in other operating costs to
provide comparability to prior periods where there were
higher manual meter reading costs.
Portfolio performance and non-recurring
•Holidays Act provision (+$6.8m) released in FY22 post
successful Metro Glass appeal, partially offset by
accounting adjustments related to software as a service
(SaaS) and impairment of thermal development costs.
•Full six months of operating costs acquired as part of
the strategic transactions of Western Energy (April 21)
and Simply Energy (September 20).
•Incentive costs are lower on current assessment of a
broad range of KPIs beyond financial performance.
Underlying movement
•General inflation of 6% impacts general operating
costs, cost efficiency achieved through digital
investment and broadband provisioning.
Growth
•Only $1m incremental investment in broadband growth
opexdespite connection growth up 73%.
•Resourcing a development team to deliver on strategic
growth priorities.
Operating costs flat despite acquisitions, strong
performance and cost pressures
Underlying savings
Insurance and general cost inflation
Invest in
growth
1H22 results
2.5
3.9
3.3
2.4
3.9
Net Cost Savings
104.2
6.8
1H21Opex associated
with acqusitions
Holidays Act, SaaS
and impairment of
Peaker development
Incentives
1.9
2.1
Growth1H22
97.4
3.4
98.2
Previously
reported
Meter
costs
Brand investment
24
Strategic fixed price400GWh$36/MWh $14m
CFDs830GWh$139/MWh$115m
C&I800GWh$104/MWh$83m
Retail1,920GWh$125/MWh$240m
Other income³$29m
$481m
Hydro1,990GWh$0/MWh-$0m
Geo1,625GWh$2/MWh-$3m
Thermal⁴480GWh$119/MWh-$57m
Acquired150GWh$131/MWh-$20m
-$80m
Length⁵$38mTransmission/Storage-$30m
Location losses⁶-$37mOperatingexpenses-$105m
Total$1mTotal-$135m
1H22assumptions that deliver expected & normalised EBITDAF of $520m over a financial year
EBITDAF reconciliation to 1H22
Hydrology & Asset
availability optimise generation
3
4
Total
x
=
Access to and price of fuel* drives
financials & risk position
Contracted sales pricing
Normalised & Expected
Higher renewables
Gas and carbon costs
Other income
Actual
Pricing on fixed channels (Retail, C&I and Strategic fixed
price) of $105/MWh lower than expected ($108/MWh)
Renewablegeneration above mean (+435GWh) saw less
thermal generation at expected thermal SRMC
Natural gas availability has led to increased cost of gas;
carbon costs continue to rise
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 $8.4/GJ, carbon price of $37/unit and thermal portfolio heat rate (11.4GJ/MWh)
5.Length of 220GWh p.a. assumed
6.Locational losses of 5.6% on spot purchases and settlement
of CFDs sold at a wholesale price of $125/MWh
Fixed costs
Opex(-$7m) lower on one-offs and spend deferral to 2H,
transmission costs lower on ACOT payments (-$6m)
volume
price
52
8
1
6
267
6
0
-3
322
13
In line with expectations
Normalised and expected EBITDAF assumptions
1H22 results
With reconciliation to actual performance
x
Wholesale channel management
Higher sales volumes through wholesale market channel
(+453GWh), pricing in merchant spot channels lower
25
•EBITDAF up $76m as higher renewable generation reduced generation costs and pricing to
wholesale channels rose.
•Working capital changes $91m unfavourable to FY20 due to the increased in quantity and value
of gas inventory, additional purchase of carbon units from contracts entered in prior periods,
reduction in gas swap payables and NZX trading movements.
•Capital expenditure (cash) $35m in FY22.
6 months
ended 31
December
2021
6 months
ended 31
December
2020
Comparison
against 1H21
EBITDAF$322m$246m↑$76m
Workingcapital changes($69m)$22m↓($91m)
Taxpaid($65m)($58m)↓($7m)
Interest paid, net of interest capitalised($15m)($23m)↑$8m
SIBcapital expenditure($35m)($31m)↓($4m)
Non-cash items includedin EBITDAF($7m)$1m↓$8m
Operating free cash flow$131m$157m↓$26m
Operating free cash flow per share16.8cps21.9cps↓5.1cps
Cash conversion (OpFCF/EBITDAF)41%64%↓23%
SIB capital expenditure –accounting ($m)
Underlying cash conversion for 1H22 impacted by investments in gas and carbon to manage risk
Cash flow and capital expenditure
Strategic investments / acquisitions
Growth investment
Dividends paid
Sources and uses of cash ($m) 1H22
131
162
79
124
73
16
12
SourcesUses
298298
64
35
29
27
31
35
0
20
40
60
80
1H221H171H181H191H201H21
Cash Movement
Debt drawdown
Operating
Free Cash Flow
1H22 results
DRP
26
•Face value of borrowings (excl. leases)
increased by $75m to $849m from 30 June
2021.The increase is due to the issuance of
$225m of capital bonds replacing $150m of
maturing retail bonds in November 21 to fund
the Tauhara geothermal power station
construction.
•Net debt has reduced by $737m since the end
of FY17.Gearing²decreased to 19.3% at31
December 2021, down from 22.6% at30 June
2021.
•The average interest rate on gross debt has
increased with the reduced use of lower cost
flexible sources of funding following the equity
raise in FY21, this is expected to reduce as debt
levels increase and these lower cost options are
again utilised.
•All bank facilities are sustainability linked loans,
and all debt instruments are certified green.
Diverse sources of funding provide capacity to support Contact’s growth strategy
Closing net debt ($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 7.9 years as at31 December 2021
Strong balance sheet
1.Gross interest includes all interest on borrowings, bank commitment fees and deferred financing costs. Unwind of leases, provisions and capitalised interest not included.
2.Gearing calculation excludes subordinated debt as per covenants
3.From FY2c based on normalised EBITDAF of $520m. Previously $480m.
1,504
1,410
990
1,036
774
849
-3
FY21
21
FY19
-47
645
24
-6
41
38
25
1,445
HY22FY18FY17
22
-44
802
FY20
968
-150
-71
1,539
1,014
Lease obligationsBorrowingsCash on hand
7
7
225
100
153
100
136
88
50
265
115
258
FY22FY52
7
372
FY23
77
107
7
FY25FY24FY26FY27
4
FY28 -
FY29
210
92
Undrawn bank facilities
Drawn bank facilities
Domestic bonds
USPP
NEXI
Capital bonds
3.0
2.7
2.2
2.0
1.81.8
3.2
3.1
2.3
2.4
1.2
1.5
FY22
normalised
3
FY19FY21FY20FY18FY17
SmoothedSnapshot
1,598
1,476
1,207
1,031
963
817
FY20
5.3%
FY17FY19
5.2%
5.4%
HY22
5.1%
FY18
5.2%
FY21
5.7%
Average gross interestAverage gross debt
1H22 results: Key balance sheet metrics
Interim dividend for 1H22 of 14 cents per share
•Interim dividend of 14 cents per share (1H21 14 cents per share) is imputed to 71% or 10 cents per share for
qualifying shareholders. This represents a pay-out of 83% of 1H22 operating free cash flow per share.
•Target FY22 dividend of 35 cps. This target dividend is 83% of the average operating free cash flow for the
preceding four years. The dividend policy is to pay-out between 80-100% of average operating free cash flow of
the preceding four years.
•Record date of 11 March 2022; payment date of 30 March 2022.
•The NZD/AUD exchange rate used for the payment of Australian dollar dividends will be set on 22 March 2022.
Ordinary dividends ($m)
Declared
Final dividendInterim dividend
61%
76%
82%
% pay-out of operating free cash flow
Dividend for 1H22
97%
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 14 March 2022 to confirm participation in the plan.
•Trading period for setting price for DRP is 10 March 2022 to 16 March 2022. DRP strike price will be
announced: 17 March 2022
83%
27
107
136
165165
163
109
79
93
115115
109
229
FY19FY17
186
280
FY18FY21FY20
280
272
1H22
2632
39
39
35
cps
14
72%
28
Guidance confirmation
Updated FY22
guidance
1H22 resultChange to prior guidance
Other operating costs
$202-212m$98m
↓
$13m
All meter costs now included in cost of goods
($13m annual), favourable actual one-off’s offset
by higher brand investment.
Stay in business capital expenditure
(cash)
$88-98m$35m
↓
$7m
Covid impacts have deferred the timing of
expected spend
Cashspend (‘Totex’)
$290 –310m$133m
↓
$20m
Depreciation and amortisation
$265–275m$129m-
Net interest (accounting)
$30 –40m$19m-
Cash interest(in operating cash flow)
$20 –30m$15m-
Cashtaxation
$85 –95m
$65m (2/3
rd
of
payments in
1H22)
-
Corporate costs
$28m$10m
↓
$5m
Updated to include the 1H22 one-offs (including
Holidays Act)
Target ordinary dividend per share
35 cps
(40%/60%)
14 cps (interim)-
Geothermal volumes
3,250 GWh1,659 GWh-
Our strategy to lead NZ’s decarbonisation
Enablers
Transformative ways of working:
create a flexible and high-performing
environment for New Zealand’s top talent
Outcomes
Growth
Pivot our business to a new growth era that
captures the value unlocked by decarbonisation
Resilience
Deliver sustainable shareholder returns,
aligned with our ESG commitment
Performance
Realise a step-change in performance, materially
growing EBITDAF through strategic investments
Strategic
theme
Objective
Grow
demand
Attract new industrial demand with
globally competitive renewables
Grow renewable
development
Build renewable generation and
flexibility on the back of new demand
Decarbonise
our portfolio
Lead an orderly transition
to renewables
Create outstanding
customer experiences
Create NZ's leading energy and services brand to
meet more of our customers’ needs
Operational excellence:
continuously improving our operations
through innovation and digitisation
ESG: create long-term value through our strong
performance across a broad set of environmental,
social and governance factors
29
30
Questions
31
Supporting
materials
32
ASX futures pricing in fuel risk over next 12 months
ASX electricity forward pricing ($/MWh)
Source: ASX Energy as at 2 February 2022
164
171
175
123
130130
90
101
112
112
80
78
85
83
70
192
200
199
149
159
159
126
140
142
108
115
110
94
Q1 2023Q3 2025Q2 2022Q1 2022Q4 2022Q2 2023Q3 2022Q2 2025
114
137
Q3 2023
116
Q4 2023Q1 2024Q2 2024Q3 2024Q4 2024Q1 2025Q4 2025
109
BENOTA
ASX futures
33
Contact generation output sold to the national grid (GWh)
Electricity and generation sales position (GWh)
1H21
1H22
Generation and sales position
Merchant sales
CFD gross sales
Sales to C&I
Sales to Customer
1,552
1,726
1,652
1,649
1,524
1,659
2,073
1,635
2,045
1,886
1,984
2,391
685
966
836
825
870
360
1H17
4,533
1H181H221H201H191H21
4,411
4,310
Thermal
generation
Hydro
generation
Geothermal
generation
4,327
4,359
4,378
4,378
1,959
4,411
1,928
189
982
162
718
48
1,198
47
1,654
476
320
Generation
Merchant sales
SalesGeneration
4,620
Sales
Direct generation
Acquired generation
Spot generation
4,6154,615
4,620
+5
Operational data
84%
Renewable % of
own generation
78%
81%
79%
91%
82%
34
Wairākeigeothermal field mass take and efficiency
Geothermal fuel extracted at Wairākeivs consented (GWh)Wairākei, Poihipiand TeMihi conversion effectiveness
(MWh per kTextracted)
% of geothermal fluid extractedWairakei mass extracted
30
25
0
35
15
5
10
20
40
45
50
1H201H191H22
94%
101%
1H171H18
100%
97%
95%
1H21
100%
+5%
30.6
31.0
32.3
30.7
30.3
31.4
1H191H171H181H201H211H22
+1%
+4%
Geothermal performance
35
Hydro generation (GWh)
Geothermal generation (GWh)
Thermal generation (GWh)
Te Huka
Ōhaaki
Poihipi
Wairākei
Te Mihi
Geothermal generation was 135GWh higher than 1H21 which
had the 4-yearly statutory TeMihi outage and an extended
outage required on process safety improvements required at the
TeHukabinary plant.
Hydro generation was 401GWh above mean (1,990GWh) in
1H22, 408GWh higher than 1H21. Inflows were consistent
throughout the period which limited spill.
Thermal generation volumes were 511GWh lower than 1H21 as a result of the
strong renewable generation and low wholesale prices.
Generation volumes:
renewable generation up by 15% on 1H21
Te Rapa -spot
Whirinaki
TeRapa -Direct generation
Stratford Peakers
TCC
Otahuhu
Total inflowsInflows storedSpill
488
719
716
709
559
692
612
539
486
493
567
531
199
209
203
181
129
168
159
161
155
171
165
170
94
99
92
95
104
99
1,649
1H221H171H18
1,726
1,524
1H19
1,659
1H211H20
1,552
1,652
2,213
1,780
2,148
2,789
2,432
2,758
-30
-197
-175
-260
-67
-35
-707
-274
-73
1H17
-110
1H221H18
-73
1H191H201H21
2,073
1,635
2,045
1,886
1,984
-107
2,391
298
463
649
593
620
168
275
369
69
119
130
87
111
133
114
111
117
104
52
50
51
50
48
47
1
875
2
0
1H181H201H17
4
1H19
3
1H21
2
1H22
736
1,016
887
918
407
Operational data
Inflows stored include uncontrolled storage lakes
36
Taranaki combined cycle (TCC)
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
1H1837751%28%46311051
1H1937763%39%64911978
1H2037778%36%59311367
1H2137796%37%62012779
1H22377100%10%16718331
Hydro
Geothermal
Peakers(including Whirinaki)
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
1H1878495%47%1,63588144
1H1978495%59%2,045129265
1H2078494%54%1,88698184
1H2178485%57%1,984110218
1H2278483%69%2,39190215
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
1H1842997%91%1,72686148
1H1942591%88%1,652137226
1H2042594%88%1,649106175
1H2142586%81%1,524118180
1H2241096%92%1,660105175
TeRapa (spot generation only)
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
1H1836098%21%37012044
1H1936079%4%7323117
1H2036078%7%12015318
1H2136088%8%13315020
1H2236084%5%8721619
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
1H184199%73%1339312
1H194198%63%11416118
1H2041100%61%11111613
1H214199%65%11712214
1H2241100%57%10410811
Plant availability
Availability Factor calculation includes all station outages (Planned, Maintenance, Forced) but does not consider plant deratings.
Operational data
37
Haweastorage (GWh)
Gas storage (PJ)
Closing storage
Closing storage
Fuel storage movements
Source: NZX hydro
53
159
152
257
90
175
166
252
294
351
244
299
229
324
-146
-302
-246
-412
-214
-237
-231
Opening storage
1H21
175
1H201H192H192H202H21
Inflows
1H22
Releases
159
152
257
90
166
260
7.5
5.6
4.5
5.0
6.1
5.0
5.7
0.8
0.6
1.5
2.2
0.8
1.7
2.4
-2.7
-1.7
-1.0
-1.1
-1.9
-0.9
-0.4
2H201H191H222H19
Gas Injected
1H20
5.0
1H21
Opening Storage
2H21
Gas Extracted
5.6
4.4
6.1
5.0
5.8
7.7
Operational data
In late 2021 we were notified of an unexpected and unexplained increase in pressure recorded in the AhuroaGas Storage Facility (AGS) by
the owner and operator of the facility, FlexGas. In conjunction with FlexGas, we will be assessing the potential implications of this on our
contractual rights over the next several months. In the interim, we will support a prudent operating regime and will adapt our injection into
the facility to maintain appropriate facility pressures. In a fuel short market, this is not expected to have any financial impact.
38
Contracted gas volumes (PJ)
Uses of gas (PJ)
Gas storage monthly injections and extractions (PJ)
Contracted and stored gas
Storage balance at31 December 2021 was 7.7PJ
Gas injectedGas extracted
4.1
6.9
4.0
7.6
8.1
3.4
10.0
4.4
4.5
4.5
4.5
4.5
6.1
5.6
1.2
3.1
3.4
4.5
2.0
5.3
6.9
4.1
6.5
2.3
-0.2
CY17
0.0
CY18CY21CY16CY19
18.4
CY20
-0.4
CY22
16.6
18.6
16.6
16.9
15.2
14.6
-0.02
0.50
-0.10
0.27
Feb-
21
-0.02
-0.37
-0.12
Mar-
21
0.36
0.50
-0.06
0.55
Apr-
21
0.04
-0.03
May-
21
Sep-
21
0.07
-0.26
Aug-
21
Jun-
21
0.26
Jul-
21
Nov-
21
Oct-
21
0.41
-0.05
0.18
Jan-
21
-0.11
-0.03
0.42
0.45
-0.11
Dec-
21
8.1
6.2
10.3
8.1
9.4
9.3
9.8
1.9
1.1
-1.1
1.1
-0.7
-2.0
-8.1
-5.8
-7.9
-5.3
-8.2
-6.7
-4.4
-1.7
-1.4
-1.8
-1.4
-1.7
-1.4
-1.6
-0.6
-1.6
2H20
-0.1
-0.2
-0.5
1H192H19
Customer sales
-0.1
Net extraction
(injection)
-0.2
Wholesale sales
1H20
-0.5
1H212H211H22
Generation
Purchases
Short-term gas
Genesis
Swap
Maui -notified
Pohokura -notified (Jan-Jun22)
Operational data
39
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
2021
6 months ended
31 December
2020
Variance onprior year
$m%
Profit13478 5672%
Depreciation and amortisation1291141513%
Change in fair valueof financial
instruments
(13)(4)(9)225%
Net interest expense1926(7)(27%)
Tax expense53322166%
EBITDAF322246 7631%
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 1H21 are as follows:
•Depreciation and amortisation: Increased by
$15m (13%) on 1H21 primarily resulting from the
review of Wairākeiplant in 2H21.
•Net interest expense: Reduced by $7m (27%) with
lower averageborrowings post 2021 equity raise as
well as the capitalisationof interest relating to the
Tauhara geothermal project.
•Tax expense for the period increased $21m
following higher operating earnings with higher
depreciation partially offset by lower net interest
expense.Tax expense for 1H22 represents an
effective tax rate of28%. The effective tax rate for
1H21 was 29%.
Non-GAAP profit measure
40
Historical financial information
Unit
1H181H191H201H211H22
Revenue$m1,1901,3631,1101,1411,139
Expenses$m9541,072889895817
EBITDAF$m236291221246322
Profit$m582765978134
Operating free cash flow$m141203120157131
Operating free cash flow per sharecps19.728.316.821.916.8
Dividends declared (interim)cps13.016.016.014.014.0
Total assets$m5,3905,1404,8504,7384,954
Total liabilities$m2,6632,2972,1702,2122,003
Total equity$m2,7272,8432,6802,5262,951
Gearing ratio¹%35.429.729.931.119.3
Historic performance
¹ Gearing ratio is calculated as: Senior debt -including finance lease liabilities/(Senior debt -including finance lease liabilities + Equity)
41
1H221H21
Reference number for
Wholesale segment
note (see following
page)
Six months ended 31 December 2021Six months ended 31 December 2020
VolumeGWAPVolumeGWAP
Note: this table has not been rounded andmight not addGWh$/MWh$mGWh$/MWh$m
Electricity sales to Retail segment1,928 103.1 199
1,95993.2183
1
Electricity sales to C&I (netback)67181.6 55
93476.772
2Electricity sales –Direct47132.7 6
48110.45
Electricity sales to C&I718 85.0 61
98279.078
CfDs–Tiwai support397
353
3
CfDs-Long term sales264
301
CfDs-Short term sales993
544
Electricity sales -CFDs1,654 114.4 189
1,19884.3101
Total contracted electricity sales4,300 104.4 449
4,13887.1361
Steam sales361 51.8 19
39044.117
4
Other income
21
5
Net income on gas sales
11
6
Net income on electricity related services
(1)1
7
Net other income
22
Total contracted revenue (1)
4,661100.74694,52884.0380
8
Generation costs4,458(27.7)(124)
4,426(34.3)(152)
Acquired generation cost162(153.7)(25)
189(117.4)(22)
9
Generation costs (including acquired generation) (2)4,620 (32.2)(149)
4,615(37.7)(174)
Spot electricity revenue4,411102.7 453
4,378117.1513
10
Settlement on acquired generation162128.4 21
189116.822
11
Spot revenue and settlement on acquired generation (GWAP)4,573 103.6 474
4,567117.1535
Spot electricity cost(2,599)(117.3)(305)
(2,893)(127.6)(369)
12
Settlement on CFDs sold(1,654)(105.2)(174)
(1,198)(119.0)(142)
13
Spot purchases and settlement on CFDs sold (LWAP)(4,253)(112.6)(479)
(4,091)(125.1)(512)
Trading, merchant revenue and losses(3)
(5)
23
Wholesale EBITDAF (1+2+3)
316
229
Wholesale segment
Segmental performance
42
Wholesale segment key
Wholesale segment
Reference to detailed operating segment
performance
Comment
Revenue
C&I electricity –Fixed Price2
C&I electricity –Spot2-spot
Spot sales are regarded as a pass-through and not reflected in performance
reporting, any margin included in C&I netback
Wholesale electricity, net of hedging3+10+13
Electricity related services revenue7
Inter-segment electricity sales1
Gas6Revenuefrom wholesale gas sales, purchase cost of gas and diesel purchases
Steam4
Other income5
Costs
Electricity purchases, net of hedging9+11+12
Electricity purchases–Spot2-spotSpot sales are regarded as a pass-through
Electricity related services cost7
Gasand diesel purchases8 (less costs identified relating to 6)Includeswholesale gas sales purchases (if any)
Gas storage costs8
Carbon emissions8
Generation transmission andreserve costs8
Electricity networks,transmission and meter costs –Fixed Price2
Electricity networks,transmission and meter costs –Spot2-spotSpot sales are regarded as a pass-through
Gas networks,transmission and meter costs8
Other operating expenses8 (less costs identified relating to 2)
C&Ioperating costs are included in the calculation of netback (2) and are
excluded from generation operating costs
Segment note to operational performance
43
Residential electricityunit1H191H201H21
1H22
Residential gasunit1H191H201H21
1H22
Average connections#352,159355,216357,756367,199Average connections#61,33261,95960,56363,182
Sales volumesGWh1,3351,3281,3491,408Sales volumesTJ936911954970
Average usageper ICP3.83.73.83.8Average usageper ICP15.314.715.715.4
Tariff$/MWh249.9248.2251.1251.5Tariff$/GJ29.130.631.332.6
Network, meters and levies$/MWh-123.9-122.5-116.2-115.9Network, meters and levies$/GJ-17.1-17.3-15.3-16.2
Energy costs$/MWh-85.4-91.6-101.1-110.8Energy costs$/GJ-5.6-7.6-8.3-11.3
Gross margin$/MWh40.634.133.824.8Carbon costs$/GJ-0.9-1.4-1.4-2.0
Gross margin$ per ICP16814112795Gross margin$/GJ5.54.36.33.2
Gross margin$m59504535Gross margin$ per ICP90709950
Gross margin$m6463
SME electricityunit1H191H20
1H211H22
SME gasunit1H191H20
1H211H22
Average connections#55,15655,29551,40748,323Average connections#3,8653,9913,8583,918
Sales volumesGWh539533465392Sales volumesTJ809845720628
Average usageper ICP9.89.69.08.1Average usageper ICP209.4211.8186.7160.4
Tariff$/MWh224.4226.7230.7239.0Tariff$/GJ14.814.915.818.6
Network, meters and levies$/MWh-108.0-113.5-104.4-113.0Network, meters and levies$/GJ-5.3-5.4-7.9-8.7
Energy costs$/MWh-83.6-89.3-99.7-109.0Energy costs$/GJ-5.6-7.6-8.3-11.3
Gross margin$/MWh32.823.926.517.0Carbon costs$/GJ-0.9-1.4-1.4-2.0
Gross margin$ per ICP335242240138Gross margin$/GJ3.00.5-1.8-3.3
Gross margin$m1813127Gross margin$ per ICP57597-474-532
Gross margin$m20-2-3
Broadband
unit1H191H20
1H211H22
Retail segment EBITDAF
1H191H20
1H211H22
Average connections#2,67717,03833,19757,498Electricity Gross margin$m72585841
Tariff$/cust/mth106.670.765.271.8Gas Gross Margin$m8451
Network, provisioning, modems$/cust/mth-91.3-68.9-74.0-61.6Broadband Gross Margin$m00-24
Gross margin$/cust/mth15.31.8-8.810.2Total Gross Margin$m80626146
Gross margin$m00-24Other income$m2233
Other operating costs$m-34-35-33-33
Retail segment EBITDAF$m48303016
Corporate allocation (50%)$m-7-7-7-5
Retail EBITDAF$m41232311
EBITDAF margins (% of revenue)%8.2%4.7%4.6%2.1%
Retail segment
Historic performance
---
2 Contact | Interim Financial Statements Contact | Interim Financial Statements 3
About these financial statements
FOR THE SIX MONTHS ENDED 31 DECEMBER 2021
These interim financial statements are for Contact, a group made up of Contact Energy Limited, the entities over which it has
control and its associate.
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 2021 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 2021
(2021 Annual Report). The Financial Statements should be read with the 2021 Annual Report.
The financial statements are prepared:
• in millions of New Zealand dollars (NZD) unless otherwise stated
• in accordance with New Zealand generally accepted accounting practice (GAAP) and comply with NZ IAS 34 Interim Financial
Reporting
• using the same accounting policies and significant estimates and critical judgments disclosed in the 2021 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 11 February 2022:
Robert McDonald Sandra Dodds
Chair Chair, Audit & Risk Committee
Statement of comprehensive income
FOR THE SIX MONTHS ENDED 31 DECEMBER 2021
$m Note
Unaudited
6 months ended
31 Dec 2021
Unaudited
6 months ended
31 Dec 2020
Audited
Year ended
30 June 2021
Revenue and other income A2 1,139 1,141 2,573
Operating expenses A2 (817) (895) (2,020)
Net interest expense B4 (19) (26) (50)
Depreciation and amortisation C1 (129) (114) (249)
Change in fair value of financial instruments D1 13 4 7
Profit before tax 187 110 261
Tax expense (53) (32) (74)
Profit 134 78 187
Items that may be reclassified to profit/(loss):
Change in hedge reserves (net of tax) 33 (9) (2)
Comprehensive income 167 69 185
Profit per share (cents) - basic and diluted 17.2 10.9 25.3
4 Contact | Interim Financial Statements
Contact | Interim Financial Statements 5
Statement of cash flows
FOR THE SIX MONTHS ENDED 31 DECEMBER 2021
$m Note
Unaudited
6 months ended
31 Dec 2021
Unaudited
6 months ended
31 Dec 2020
Audited
Year ended
30 June 2021
Receipts from customers 1,211 1,182 2,524
Payments to suppliers and employees (965) (914) (1,970)
Interest paid
(15) (22) (43)
Tax paid (65) (58) (79)
Operating cash flows 166 188 432
Purchase and construction of assets (151) (36) (129)
Capitalised interest
(8) (4) (8)
Investment in associate (6) (4) (8)
Acquisition of subsidiaries and Energyclubnz (5) - (32)
Investing cash flows (170) (44) (177)
Dividends paid B2 (145) (165) (274)
Proceeds from borrowings 267 240 356
Repayment of borrowings (193) (227) (623)
Financing costs
(4) - -
Net proceeds from share issue - - 392
Financing cash flows (75) (152) (149)
Net cash flow (79) (8) 106
Add: cash at the beginning of the period 150 44 44
Cash at the end of the period 71 36 150
Statement of financial position
AT 31 DECEMBER 2021
$m Note
Unaudited
31 Dec 2021
Unaudited
31 Dec 2020
Audited
30 June 2021
Cash and cash equivalents 71 36 150
Trade and other receivables 186 148 255
Inventories 87 53 69
Intangible assets C1 64 29 24
Derivative financial instruments D1 29 22 56
Total current assets 437 288 554
Property, plant and equipment C1 4,024 3,963 3,961
Intangible assets C1 205 217 221
Goodwill C2 214 201 214
Investment in associate
16 6 10
Derivative financial instruments D1 82 63 70
Total non-current assets 4,541 4,450 4,476
Total assets 4,978 4,738 5,030
Trade and other payables 235 192 305
Tax payable 33 12 39
Borrowings B3 115 247 163
Derivative financial instruments D1 54 64 92
Provisions 14 18 23
Total current liabilities 451 533 622
Borrowings B3 814 890 693
Derivative financial instruments D1 50 79 84
Provisions 53 59 51
Deferred tax 645 638 637
Other non-current liabilities 14 13 16
Total non-current liabilities 1,576 1,679 1,481
Total liabilities 2,027 2,212 2,103
Net assets 2,951 2,526 2,927
Share capital B1 1,944 1,530 1,922
Retained earnings 1,019 1,047 1,048
Hedge reserves (18) (58) (51)
Share-based compensation reserve 6 7 8
Shareholders' equity 2,951 2,526 2,927
6 Contact | Interim Financial Statements
Contact | Interim Financial Statements 7
Statement of changes in equity
FOR THE SIX MONTHS ENDED 31 DECEMBER 2021
$m Note Share capital
Retained
earnings
Other
reserves
Shareholders'
equity
Balance at 1 July 2020 1,528 1,134 (41) 2,621
Profit A2 - 78 - 78
Change in hedge reserves (net of tax) - - (9) (9)
Change in share-based compensation reserve - - (1) (1)
Change in share capital B1 2 - - 2
Dividends paid B2 - (165) - (165)
Unaudited balance at 31 December 2020 1,530 1,047 (51) 2,526
Profit A2 - 109 - 109
Change in hedge reserves (net of tax) - - 7 7
Change in share-based compensation reserve - - (1) (1)
Change in share capital B1 392 - - 392
Dividends paid B2 - (109) - (109)
Audited balance at 30 June 2021 1,922 1,048 (43) 2,927
Profit 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
A. Our performance
Notes to the financial statements for the six months ended 31 December 2021
A1. SEGMENTS
Contact reports activities under the Wholesale segment and the Retail (previously named ‘Customer’) 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, following their acquisition in the prior year ended 30
June 2021, have been included in the Wholesale segment within the relevant line items.
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.
A2. EARNINGS
The tables on the next pages provide a breakdown of Contact’s revenue and expenses, 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 reported under NZ GAAP. EBITDAF is used to monitor performance and is a non-GAAP profit measure.
$6 million of metering costs, included within ‘Other operating expenses’ in prior reporting periods, have been reclassified to
‘Electricity networks, levies & meter costs’ in the six months ended 31 December 2021. Prior year comparatives are also reclassified
(31 December 2020: $7 million, 30 June 2021: $12 million) to conform with the current period’s presentation with no net impact on
total operating expenses or EBITDAF. The reclassification has been made to better reflect the direct nature of these costs and to
improve comparability with the industry.
8 Contact | Interim Financial Statements
Contact | Interim Financial Statements 9
Unaudited 6 months ended 31 Dec 2021 Unaudited 6 months ended 31 Dec 2020 Audited year ended 30 June 2021
$m Wholesale Retail Unallocated Eliminations Total Wholesale Retail Unallocated Eliminations Total Wholesale Retail Unallocated Eliminations Total
Mass market electricity - 448 - - 448 - 446 - - 446 - 839 - (1) 838
C&I electricity - fixed price 100 - - - 100 126 - - - 126 249 - - - 249
C&I electricity - pass through 15 - - - 15 18 - - - 18 44 - - - 44
Wholesale electricity, net of hedging 476 - - - 476 471 - - - 471 1,285 - - - 1,285
Electricity-related services revenue 4 - - - 4 4 - - - 4 8 - - - 8
Inter-segment electricity sales 199 - - (199) - 183 - - (183) - 338 - - (338) -
Gas 3 43 - - 46 1 41 - - 42 2 74 - - 76
Steam 19 - - - 19 17 - - - 17 28 - - - 28
Geothermal services 1 - - - 1 - - - - - 3 - - - 3
Broadband - 25 - - 25 - 13 - - 13 - 32 - - 32
Total revenue 815 516 - (199) 1,132 820 500 - (183) 1,137 1,957 945 - (339) 2,563
Other income 4 3 - - 7 1 3 - - 4 4 6 - - 10
Total revenue and other income 819 519 - (199) 1,139 821 503 - (183) 1,141 1,961 951 - (339) 2,573
Electricity purchases, net of hedging (318) - - - (318) (371) - - - (371) (974) - - - (974)
Electricity purchases - pass through (9) - - - (9) (14) - - - (14) (30) - - - (30)
Electricity related services cost (5) - - - (5) (3) - - - (3) (7) - - - (7)
Inter-segment electricity purchases - (199) - 199 - - (183) - 183 - - (338) - 338 -
Gas and diesel purchases (42) (18) - - (60) (60) (14) - - (74) (126) (24) - - (150)
Gas storage costs (11) - - - (11) (12) - - - (12) (24) - - - (24)
Carbon emissions costs (13) (3) - - (16) (16) (2) - - (18) (41) (4) - - (45)
Generation transmission & levies (9) - - - (9) (14) - - - (14) (28) - - - (28)
Electricity networks, levies & meter costs - fixed price (32) (208) - - (240) (43) (206) - - (249) (82) (390) - - (472)
Electricity networks, levies & meter costs - pass through (5) - - - (5) (4) - - - (4) (13) - - - (13)
Gas networks, transmission & meter costs (3) (21) - - (24) (4) (20) - - (24) (7) (38) - - (45)
Geothermal service costs (1) - - - (1) - - - - - (1) - - - (1)
Broadband costs - (21) - - (21) - (15) - - (15) - (33) - - (33)
Other operating expenses (55) (33) (10) - (98) (51) (33) (13) - (97) (101) (68) (30) 1 (198)
Total operating expenses (503) (503) (10) 199 (817) (592) (473) (13) 183 (895) (1,434) (895) (30) 339 (2,020)
EBITDAF 316 16 (10) - 322 229 30 (13) - 246 527 56 (30) - 553
Depreciation and amortisation
(129)
(114)
(249)
Net interest expense
(19)
(26)
(50)
Change in fair value of financial instruments
13
4
7
Tax expense
(53)
(32)
(74)
Profit 134 78 187
10 Contact | Interim Financial Statements
Contact | Interim Financial Statements 11
A3. FREE CASH FLOW
$m
Unaudited
6 months ended
31 Dec 2021
Unaudited
6 months ended
31 Dec 2020
Audited
Year ended
30 June 2021
EBITDAF 322 246 553
Tax paid (65) (58) (79)
Change in working capital, net of investing and financing activities (69) 21 3
Non-cash items included in EBITDAF (7) 1 (2)
Net interest paid, excluding capitalised interest (15) (22) (43)
Operating cash flows 166 188 432
Stay in business capital expenditure (35) (31) (61)
Operating free cash flow and free cash flow 131 157 371
Operating free cash flow per share (cents) 16.8 21.9 50.2
A4. RELATED PARTY TRANSACTIONS
Contact’s related parties include its directors, the leadership team (LT) and Drylandcarbon One Limited Partnership.
$m
Unaudited
6 months ended
31 Dec 2021
Unaudited
6 months ended
31 Dec 2020
Audited
Year ended
30 June 2021
Simply Energy Limited
Electricity contracts - 1 1
Drylandcarbon One Limited Partnership
Capital contributions (6) (3) (7)
Key management personnel
Directors' fees (1) (1) (1)
LT - salary and other short-term benefits (5) (3) (5)
LT - share-based compensation expense (1) - (1)
Members of the LT and Directors 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.
LT disclosures include members who served during the period but are no longer acting in role at 31 December 2021.
A5. CONTINGENCIES
In the normal course of business, the Company is subject to inquiries, claims and investigations. There are no matters that meet the
requirements to disclose in this respect at 31 December 2021.
B. Our funding
Notes to the financial statements for the six months ended 31 December 2021
B1. SHARE CAPITAL
Number $m
Balance at 1 July 2020 718,131,884 1,528
Share capital issued 434,021 2
Balance at 31 December 2020 718,565,905 1,530
Share capital issued 57,556,165 392
Balance at 30 June 2021 776,122,070 1,922
Share capital issued 3,001,936 22
Balance at 31 December 2021 779,124,006 1,944
Comprised of:
Ordinary shares 778,875,270 1,945
Contact Share 248,736 (1)
During the period Contact granted a new tranche of share awards under the Equity Scheme, comprising 232,556 performance
share rights (PSRs) and 497,697 deferred share rights (DSRs). PSRs and DSRs have no exercise price.
B2. DIVIDENDS PAID
$m Cents per share
Unaudited
6 months ended
31 Dec 2021
Unaudited
6 months ended
31 Dec 2020
Audited
Year ended
30 June 2021
2020 final dividend 23 - 165 165
2021 interim dividend 14 - - 109
2021 final dividend 21 162 - -
162 165 274
The 2021 final dividend includes $17 million reinvested by shareholders under Contact's Dividend Reinvestment Plan.
On 11 February 2022 the Board declared an interim dividend of 14 cents per share to be paid on 30 March 2022.
12 Contact | Interim Financial Statements
Contact | Interim Financial Statements 13
B3. BORROWINGS
$m
Unaudited
31 Dec 2021
Unaudited
31 Dec 2020
Audited
30 June 2021
Bank overdraft 5 4 -
*Commercial paper - 80 -
*Drawn bank facilities - 191 -
Lease obligations 24 22 21
*Retail bonds 200 350 350
*Capital bonds 225 - -
*Export credit agency facility
43 50 47
*USPP notes
376 376 376
Face value of borrowings 873 1,073 795
Deferred financing costs (6) (4) (3)
Fair value adjustment on hedged borrowings 62 68 64
Carrying value of borrowings 929 1,137 856
Current 115 247 163
Non-current 814 890 693
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 2021 Contact remains compliant with the requirements of the
programme. Further information is available on the sustainability section on our website.
B4. NET INTEREST EXPENSE
$m
Unaudited
6 months ended
31 Dec 2021
Unaudited
6 months ended
31 Dec 2020
Audited
Year ended
30 June 2021
Interest expense on borrowings (24) (27) (52)
Interest expense on finance leases - - (1)
Unwind of discount on provisions (3) (3) (5)
Unwind of deferred financing costs - - (1)
Capitalised interest 8 4 8
Interest income - - 1
Net interest expense (19) (26) (50)
C. Our assets
Notes to the financial statements for the six months ended 31 December 2021
C1. PROPERTY, PLANT AND EQUIPMENT AND INTANGIBLE ASSETS
Property, plant and equipment
$m
Unaudited
31 Dec 2021
Unaudited
31 Dec 2020
Audited
30 June 2021
Opening balance 3,961 4,026 4,026
Additions 171 32 135
Acquisitions - - 10
Disposals (3) - (2)
Depreciation (105) (95) (208)
Closing balance 4,024 3,963 3,961
Included within property, plant and equipment is $28 million (31 December 2020: $25 million, 30 June 2021: $27 million) of lease
assets with a depreciation charge of $2 million for the six months ended 31 December 2021 (31 December 2020: $2 million, 30
June 2021: $3 million).
Included within additions is capitalised interest of $8 million (31 December 2020: $4 million, 30 June 2021: $8 million) in relation
to capital works underway at the Tauhara geothermal field.
Intangibles
$m
Unaudited
31 Dec 2021
Unaudited
31 Dec 2020
Audited
30 June 2021
Opening balance 245 230 230
Additions 67 35 87
Acquisitions - - 16
Disposals (19) - (47)
Amortisation (24) (19) (41)
Closing balance 269 246 245
Current 64 29 24
Non-current 205 217 221
At 31 December 2021, Contact was committed to $263 million of contracted capital expenditure (31 December 2020 $8 million, 30
June 2021: $334 million) and $68 million of carbon forward contracts (31 December 2020: $8 million, 30 June 2021: $60 million), of
which $236 million is due within one year of reporting date.
During the six months ended 31 December 2021, Contact concluded its review of existing software assets in light of the IFRS agenda
decision Configuration or Customisation costs in a Cloud Computing Arrangement and wrote off $1 million of software assets
relating to software-as-a-service arrangements.
14 Contact | Interim Financial Statements
Contact | Interim Financial Statements 15
C2. GOODWILL
Contact has two cash-generating units (CGUs): Wholesale and Customer. The Customer CGU includes goodwill of $179 million (31
December 2020 and 30 June 2021: $179 million), and the Wholesale CGU includes goodwill of $35 million, following acquisition of
Simply Energy Limited and Western Energy Services Limited in the prior period (31 December 2020: $23 million and 30 June 2021:
$41 million).
The acquisition accounting for Western Energy Services Limited was finalised in the six months ended 31 December 2021. $8
million has been allocated to brand and intellectual property, with a related $2m deferred tax liability, resulting in a $6 million
reduction of goodwill. Refer to the related parties disclosure in the 2021 Annual Report for provisional calculations at 30 June 2021,
which have been restated.
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 2021
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.
Unaudited at 31 December 2021 Unaudited at 31 December 2020 Audited at 30 June 2021
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 3 60 14 14 3 17 111 9 59 1 5 - 11 85 5 59 5 32 3 22 126
Carrying value of derivatives - liability (2) (3) (26) (51) (2) (21) (104) - (7) (75) (52) - (9) (143) - (5) (53) (93) (2) (24) (176)
Carrying value of hedged borrowings (347) (437) - -
-
- (784) (196) (435) - - - - (631) (192) (436) - - - - (628)
Fair value adjustments to borrowings (1) (61) - - - - (62) (9) (59) - - - - (68) (5) (59) - - - - (64)
Change in fair value of financial
instruments to profit/(loss) - - 15 -
-
(2) 13 - 1 2 - - 1 4 - - 8 - - (1) 7
Hedge effectiveness recognised in OCI - 2 18 (12)
-
- 8 - (6) 11 (43) - - (38) - (3) 27 (61) 1 - (37)
Amounts reclassified to profit/(loss) - - 3 36 - - 39 - - 3 21 - - 24 - - 7 25 - - 32
The cross-currency interest rate swaps (CCIRS) liability arises from the cash flow hedge component.
18 Contact | Interim Financial Statements
Contact | Interim Financial Statements 19
Conclusion
Based on our review, nothing has come to our attention that
causes us to believe that the interim financial statements on
pages 2 to 17 do not:
i. present fairly in all material respects the company’s financial
position as at 31 December 2021 and its financial performance
and cash flows for the six month period ended on that date; and
ii. comply with NZ IAS 34 Interim Financial Reporting.
We have completed a review of the accompanying interim
financial statements which comprise:
• the statement of financial position as at 31 December 2021;
• the statements of comprehensive income, changes in equity
and cash flows for the six month period then ended; and
• notes, including a summary of significant accounting policies
and other explanatory information.
Basis for conclusion
A review of interim financial statements in accordance with NZ
SRE 2410 Review of Financial Statements Performed by the
Independent Auditor of the Entity (“NZ SRE 2410”) is a limited
assurance engagement. The auditor performs procedures,
consisting of making enquiries, primarily of persons responsible
for financial and accounting matters, and applying analytical and
other review procedures.
As the auditor of Contact Energy Limited, NZ SRE 2410 requires
that we comply with the ethical requirements relevant to the
audit of the annual financial statements.
Our firm has also provided other services to the company in
relation to Trustee reporting and other assurance for Greenhouse
gas emissions reporting, Global Reporting Initiative Indicators and
Green Borrowings Programme reporting. Subject to certain
restrictions, partners and employees of our firm may also deal
with the company on normal terms within the ordinary course of
trading activities of the business of the company. These matters
have not impaired our independence as reviewer of the company.
The firm has no other relationship with, or interest in, the
company.
Use of this Independent Review Report
This report is made solely to the shareholders as a body. Our
review work has been undertaken so that we might state to the
shareholders those matters we are required to state to them in
the Independent 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 shareholders as a body for
our review work, this report, or any of the opinions we have
formed.
Responsibilities of the Directors for the interim financial
statements
The Directors, on behalf of the company, are responsible for:
• the preparation and fair presentation of the interim financial
statements in accordance with NZ IAS 34 Interim Financial
Reporting;
• implementing necessary internal control to enable the
preparation of interim financial statements that is fairly
presented and free from material misstatement, whether
due to fraud or error; and
• assessing the ability to continue as a going concern. This
includes disclosing, as applicable, matters related to going
concern and using the going concern basis of accounting
unless they either intend to liquidate or to cease operations,
or have no realistic alternative but to do so.
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. We conducted our
review in accordance with NZ SRE 2410. NZ SRE 2410 requires us
to conclude whether anything has come to our attention that
causes us to believe that the interim financial statements are not
prepared, in all material respects, in accordance with NZ IAS 34
Interim Financial Reporting.
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). Accordingly,
we do not express an audit opinion on these interim financial
statements.
This description forms part of our Independent Review Report.
KPMG
Wellington
11 February 2022
Corporate directory
BOARD OF DIRECTORS
Robert McDonald (Chair)
Victoria Crone
Sandra Dodds
Jon Macdonald
Rukumoana Schaafhausen
David Smol
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
Phone: +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
KPMG
PO BOX 996
Wellington 6140
COMPANY SECRETARY
Kirsten Clayton
General Counsel & 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
Phone: +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
Phone: +61 2 8280 7111
INVESTOR ENQUIRIES
Matthew Forbes
GM Corporate Finance
investor.centre@contactenergy.co.nz
SUSTAINABILITY ENQUIRIES
Katy Glenie
Sustainability Manager
katy.glenie@contactenergy.co.nz
To the shareholders of Contact Energy Limited
Report on the interim financial statements
Independent review report
---
Results announcement
(for Equity Security issuer/Equity and Debt Security issuer)
Results for announcement to the market
Name of issuer Contact Energy Limited
Reporting Period 6 months to 31 December 2021
Previous Reporting Period 6 months to 31 December 2020
Currency NZD
Amount (000s) Percentage change
Revenue from continuing
operations
$1,139,000 -0.2%
Total Revenue $1,139,000 -0.2%
Net profit/(loss) from
continuing operations
$134,000 71.8%
Total net profit/(loss) $134,000 71.8%
Interim/Final Dividend
Amount per Quoted Equity
Security
$0.14000000
Imputed amount per Quoted
Equity Security
$0.03888889
Record Date 11 March 2022
Dividend Payment Date 30 March 2022
Current period Prior comparable period
Net tangible assets per
Quoted Equity Security
$3.17 $2.89
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
Matthew Forbes, GM Corporate Finance
Contact phone number +64 21 072 8578
Contact email address investor.centre@contactenergy.co.nz
Date of release through MAP
14/02/2022
Unaudited financial statements accompany this announcement.
---
Distribution Notice
Please note: all cash amounts in this form should be provided to 8 decimal places
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 11/03/2022
Ex-Date (one business day before the
Record Date)
10/03/2022
Payment date (and allotment date for
DRP)
30/03/2022
Total monies associated with the
distribution
1
$109,077,361
(779,124,006 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
2
$0.17888889
Gross taxable amount
3
$0.17888889
Total cash distribution
4
$0.14000000
Excluded amount (applicable to listed
PIEs)
N/A
Supplementary distribution amount $0.01764706
Section 3: Imputation credits and Resident Withholding Tax
5
Is the distribution imputed Fully imputed
Partial imputation
No imputation
1
Continuous issuers should indicate that this is based on the number of units on issue at the date of the form
2
“Gross distribution” is the total cash distribution plus the amount of imputation credits, per financial product, before the deduction of
Resident Withholding Tax (RWT).
3
“Gross taxable amount” is the gross distribution minus any excluded income.
4
“Total cash distribution” is the cash distribution excluding imputation credits, per financial product, before the deduction of RWT.
This should include any excluded amounts, where applicable to listed PIEs.
5
The imputation credits plus the RWT amount is 33% of the gross taxable amount for the purposes of this form. If the distribution is
fully imputed the imputation credits will be 28% of the gross taxable amount with remaining 5% being RWT. This does not constitute
advice as to whether or not RWT needs to be withheld.
If fully or partially imputed, please
state imputation rate as % applied
6
22%
Imputation tax credits per financial
product
$0.03888889
Resident Withholding Tax per
financial product
$0.02014444
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
10/03/2022 16/03/2022
Date strike price to be announced (if
not available at this time)
17/03/2022
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
14/03/2022
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
Matthew Forbes, GM Corporate Finance
Contact phone number +64 21 072 8578
Contact email address investor.centre@contactenergy.co.nz
Date of release through MAP
14/02/2022
6
Calculated as (imputation credits/gross taxable amount) x 100. Fully imputed dividends will be 28% as a % rate applied.
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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