CEN performance demonstrates underlying business health
Contact Energy Limited Level 2 Harbour City Tower, 29 Brandon Street, Wellington 6011 | PO Box 10742, Wellington 6143
P: +64 4 499 4001 | W: contactenergy.co.nz
19 February 2024
Contact Energy performance demonstrates
underlying business health; Focus on asset
delivery
Six months ended
31 December 2023
1H24
Six months ended
31 December 2022
1H23
Underlying
i
Reported Against underlying
EBITDAF
ii
$325m $354m ↑ 26% from $257m
Profit $134m
$153m ↑ 70% from $79m
Profit per share 17.2 cps
19.5 cps ↑ 70% from 10.1 cps
Operating free cash flow
iii
$187m ↑ 163% from $71m
Stay-in-business capital expenditure (cash) $64m ↑ 16% from $55m
Growth capital expenditure (cash) $233m ↑ 7% from $217m
Financial performance
Contact Energy has reported net profit of $153m in 1H24 and operating earnings (EBITDAF)
of $354m. Reported figures include a net provision release relating to the Ahuroa Gas
Storage facility (AGS) onerous contract of $29m within EBITDAF ($19m within net profit after
tax and interest). Excluding the provision release, underlying net profit was up 70% on 1H23
to $134m and EBITDAF was up 26% to $325m.
The improved operating result was driven by closer alignment of channel pricing to the
wholesale market and greater thermal efficiency, partially offset by lower hydro generation,
reduced steam revenue following the closure of Te Rapa and one-off write-offs of $8m
relating to damage to Peaker assets and the CRM system upgrade programme not
continuing as originally planned.
Hydro volatility characterised operating conditions throughout the period, with flow-on
impacts to wholesale pricing from more thermal generation. Contact increased contracted
sales volumes in anticipation of Tauhara coming online in 4Q 2023 and with the delay to 3Q
2024 applied some mitigations to meet this position. At the same time, Contact has executed
well on its channel mix and pricing strategies.
“The result has been a demonstration of strength in our underlying performance, setting us
up well for the year ahead and we now expect to deliver underlying EBITDAF of $620m in
FY24,” says Chief Executive Mike Fuge.
Operating free cash flow of $187m was up 163% on the prior year on the improved
operating result, relatively lower levels of working capital due to higher thermal generation
and lower tax paid on FY23 profit, partially offset by accelerated stay in business capex. The
Board declared an interim dividend of 14 cents per share, in line with 1H23.
Contact Energy Ltd
2
Demand
Negotiations with Rio Tinto have been constructive and have re-enforced Contact’s long-
held view that the New Zealand Aluminium Smelter (NZAS) appears likely to stay. Contact is
expecting a new agreement to be long-term, at a fair price materially above the current
pricing, and including demand response (mitigating dry-year risk).
“A new long-term agreement would de-risk investment in new renewable generation,
contribute to energy security and help to preserve an important export industry, supporting
growth and decarbonisation of the New Zealand economy,” said Mr Fuge.
Renewable development
Remediation works got underway at Contact’s Tauhara geothermal development in
November and re-construction of the steam separation plant is near complete. Tauhara is
expected to come online in Q3 2024 at the initial design capacity of around 152MW
(expecting 174MW from the first planned outage in 2025), and Te Huka 3 is on track to
follow in Q4 2024
iv
.
“I’m extremely proud of the team that has worked hard over the summer to get Tauhara back
into the full swing of commissioning. Both Tauhara and Te Huka will join Contact’s
renewable generation fleet in 2024 and will add 1.9TWh per annum of baseload renewable
output once full capacity is reached.”
Drilling, advanced steamfield design and tendering have progressed to prepare for a final
investment decision in 2024 on GeoFuture, the replacement of Contact’s 65-year-old
Wairākei geothermal plant. Final investment decisions are also expected in 2024 on a
100MW North Island battery and the Kōwhai Park solar development.
“These investments in new renewable technologies will contribute to security of supply as
New Zealand decarbonises, said Mr Fuge”.
Decarbonising the portfolio
Emissions intensity from thermal generation was down ~30% on 1H23 driven largely by the
closure of Te Rapa on 30 June 2023. Portfolio decarbonisation is just one aspect of
Contact’s broader commitment to sustainability, which in December saw Contact win both
the Sustainability Leadership award in the Deloitte Top 200 and move into the number one
ranking of participating New Zealand companies in the DJSI Asia Pacific.
Contact expects to decommission its combined cycle gas generation plant (TCC) at the end
of 2024. A planned outage at TCC was brought forward and completed in December with
additional operating hours approved. Contact has also worked to accelerate the return of its
spare peaker engine and is expecting GT22 to be in service for winter 2024.
Retail
Retail electricity net price has improved in light of rising energy and pass-through costs.
Total connections were up 20,000 on 1H23, driven primarily by broadband. Contact also
expanded its telecommunication offering with the introduction of Contact Mobile and boosted
its time of use offerings with the introduction of Good Weekends. Contact remains focused
on supporting our customers in energy hardship through ERANZ, with offerings like
ConnectMe and EnergyMate, and directly with community groups like Women’s Refuge and
Good Shepherd. Over the last twelve months Contact has provided in excess of one million
dollars to directly support customers in energy hardship.
Contact Energy Ltd
3
Outlook
Looking ahead, Mr Fuge said the next six months will see Contact reaching significant
milestones in the delivery of its strategy to lead the decarbonisation of New Zealand.
“We are excited about the future. We have a clear strategy, strong balance sheet with
supportive shareholders and stand ready to deliver on the opportunities in front of us to lead
the decarbonisation of the New Zealand economy over the next decade.”
1/ MORE INFORMATION
Investor enquiries
Shelley Hollingsworth
Investor Relations and Strategy Manager
+64 27 227 2429
shelley.hollingsworth@contactenergy.co.nz
Media enquiries
Louise Wright
Head of Communications and Reputation
+64 21 840 313
louise.wright@contactenergy.co.nz
2/ CONFERENCE CALL
A conference call to support the interim results announcement will be held at 10am, NZ (New
Zealand) time on 19 February 2024.
If you would like to attend the live presentation, please see the details below to view the webcast
off your chosen device:
Click here to enter the webcast: LIVE EVENT LINK
Or access this link via our website: https://contact.co.nz/aboutus/investor-centre
i
The onerous contract provision for AGS is assessed every 6 months in line with NZ IAS 37. In 1H24 there has been a net provision release
resulting in impacts of $29m EBITDAF and $19m profit. Underlying performance excludes these impacts. All variances and commentary reflect
movements in underlying performance.
ii
Refer to slide 38 of the 2024 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). Contact
has made reclassifications to better align with IFRIC guidance on IFRS 9 resulting in realised gains/losses from market derivatives not in a hedge
relationship (includes market making activity) no longer being reported in operating income (EBITDAF). 1H23 figures restated accordingly.
iii
Refer to Note A3 of the 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.
iv
Calendar year references.
---
2024
Interim Financial
Statements
2 Contact | Interim Financial Statements Contact | Interim Financial Statements 3
About these financial statements
FOR THE SIX MONTHS ENDED 31 DECEMBER 2023
These interim financial statements are for Contact, a group made up of Contact Energy Limited, its subsidiaries and its interests in
associates and joint arrangements.
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 2023 provide a summary of Contact’s performance
for the period and outline any significant changes to information reported in the financial statements for the year ended 30 June
2023 (2023 Integrated Report). The interim financial statements should be read with the 2023 Integrated Report.
Contact’s interim 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 2023 Annual Report unless
otherwise noted.
• with certain comparative amounts reclassified to conform to the current period’s presentation.
The interim financial statements were authorised on behalf of the Contact Energy Limited Board of Directors on 16 February 2024:
Robert McDonald Sandra Dodds
Chair Chair, Audit & Risk Committee
Statement of comprehensive income
FOR THE SIX MONTHS ENDED 31 DECEMBER 2023
$m Note
Unaudited
6 months ended
31 Dec 2023
Unaudited
6 months ended
31 Dec 2022
Audited
Year ended
30 June 2023
Revenue A2 1,306 994 2,118
Operating expenses A2 (950) (832) (1,613)
Net interest B4 (20) (19) (41)
Depreciation and amortisation C1 (126) (111) (224)
Change in fair value of financial instruments D1 3 (42) (63)
Profit/(loss) before tax 213 (9) 177
Tax expense (60) 2 (50)
Profit/(loss) 153 (7) 127
Items that may be reclassified to profit/(loss):
Change in hedge reserves (net of tax) D1 (125) (30) 73
Comprehensive income 28 (37) 200
Profit/(loss) per share (cents) - basic and diluted 19.5 (0.9) 16.3
4 Contact | Interim Financial Statements
Contact | Interim Financial Statements 5
Statement of cash flows
FOR THE SIX MONTHS ENDED 31 DECEMBER 2023
$m Note
Unaudited
6 months ended
31 Dec 2023
Unaudited
6 months ended
31 Dec 2022
Audited
Year ended
30 June 2023
Receipts from customers 1,353 1,034 2,117
Payments to suppliers and employees (1,027) (820) (1,592)
Interest paid
(9) (12) (25)
Tax paid (66) (76) (105)
Operating cash flows 251 126 395
Purchase and construction of assets
(262) (272) (541)
Capitalised interest
(35) (17) (44)
Realised gains/losses on market derivatives
(2) (11) (27)
Investment in associates
(2) (4) (11)
Proceeds from sale of assets
- 4 16
Deferred consideration for acquisition of subsidiaries - (11) (11)
Investing cash flows (301) (311) (618)
Dividends paid B2 (150) (146) (243)
Proceeds from borrowings 526 643 1,092
Repayment of borrowings (191) (315) (650)
Financing costs
(1) (2) (4)
Financing cash flows 184 180 195
Net cash flow 134 (5) (28)
Add: cash at the beginning of the period 140 168 168
Cash at the end of the period 274 163 140
Statement of financial position
AT 31 DECEMBER 2023
$m Note
Unaudited
31 Dec 2023
Unaudited
31 Dec 2022
Audited
30 June 2023
Cash and cash equivalents 274 163 140
Trade and other receivables 219 211 249
Inventories 44 39 48
Intangible assets C1 116 72 33
Derivative financial instruments D1 40 59 123
Assets held for sale
- 5 -
Total current assets 692 549 593
Property, plant and equipment C1 4,771 4,293 4,615
Intangible assets C1 202 197 202
Inventories
37 36 37
Goodwill
214 214 214
Investment in associates
32 24 31
Derivative financial instruments D1 111 95 116
Total non-current assets 5,367 4,859 5,215
Total assets 6,059 5,408 5,808
Trade and other payables 290 252 275
Tax payable 26 1 33
Borrowings B3 356 415 384
Derivative financial instruments D1 125 121 83
Provisions 5 6 5
Total current liabilities 802 795 780
Borrowings B3 1,539 985 1,172
Derivative financial instruments D1 191 197 159
Provisions 256 183 277
Deferred tax 542 563 589
Other non-current liabilities 45 26 27
Total non-current liabilities 2,573 1,953 2,224
Total liabilities 3,375 2,748 3,004
Net assets 2,684 2,660 2,804
Share capital B1 2,008 1,976 1,988
Retained earnings 802 788 813
Hedge reserves (134) (113) (9)
Share-based compensation reserve 8 9 11
Shareholders' equity 2,684 2,660 2,804
6 Contact | Interim Financial Statements
Contact | Interim Financial Statements 7
Statement of changes in equity
FOR THE SIX MONTHS ENDED 31 DECEMBER 2023
$m Note
Share
capital
Retained
earnings
Hedge
reserves
Share-based
compensation
reserves
Shareholders'
equity
Balance at 1 July 2022 1,955 958 (82) 8 2,840
Profit/(loss) A2 - (7) - - (7)
Change in hedge reserves (net of tax)
- - (30) - (30)
Change in share capital B1 21 - - - 21
Dividends paid B2 - (164) - - (164)
Unaudited balance at 31 December 2022 1,976 788 (112) 8 2,660
Profit/(loss) A2 - 134 - - 134
Change in hedge reserves (net of tax)
- - 103 - 103
Change in share-based compensation reserve
- - - 3 3
Change in share capital B1 12 - - - 12
Dividends paid B2 - (108) - - (108)
Audited balance at 30 June 2023 1,988 813 (9) 11 2,804
Profit/(loss) A2 - 153 - - 153
Change in hedge reserves (net of tax) - - (125) - (125)
Change in share-based compensation reserve - - - (3) (3)
Change in share capital B1 20 - - - 20
Dividends paid B2 - (165) - - (165)
Unaudited balance at 31 December 2023 2,008 802 (134) 8 2,684
A. Our performance
Notes to the interim financial statements for the six months ended 31 December 2023
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, mobile and other products and services to
mass market customers less the cost of purchasing those products and services, and the cost to serve and distribute electricity to
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. Change in fair value of financial instruments in the Statement of Comprehensive Income includes both ‘realised gains/(losses) on risk management derivatives not in a hedge relationship’ and, 'change in fair value
of financial instruments’ from the table below.
Unaudited 6 months ended 31 Dec 2023 Unaudited 6 months ended 31 Dec 2022 Audited year ended 30 June 2023
$m Wholesale Retail Unallocated Eliminations Total Wholesale Retail Unallocated Eliminations Total Wholesale Retail Unallocated Eliminations Total
Mass market electricity - 524 - (1) 523 - 482 - - 482 - 937 - (1) 936
C&I electricity - fixed price 112 - - - 112 126 - - - 126 243 - - - 243
C&I electricity - pass through 18 - - - 18 9 - - - 9 23 - - - 23
Wholesale electricity, net of hedging 545 - - - 545 260 - - - 260 685 - - - 685
Electricity-related services revenue 2 - - - 2 6 - - - 6 12 - - - 12
Inter-segment electricity sales 280 - - (280) - 241 - - (241) - 482 - - (482) -
Gas 7 51 - - 58 3 48 - - 51 5 90 - - 95
Steam 2 - - - 2 19 - - - 19 35 - - - 35
Geothermal services 3 - - - 3 3 - - - 3 6 - - - 6
Broadband - 39 - - 39 - 32 - - 32 - 66 - - 66
Other income - 4 - - 4 - 6 - - 6 8 9 - - 17
Total revenue 969 618 - (281) 1,306 667 568 - (241) 994 1,499 1,102 - (483) 2,118
Electricity purchases, net of hedging (375) - - - (375) (190) - - - (190) (479) - - - (479)
Electricity purchases - pass through (13) - - - (13) (5) - - - (5) (16) - - - (16)
Electricity related services cost (3) - - - (3) (3) - - - (3) (6) - - - (6)
Inter-segment electricity purchases - (280) - 280 - - (241) - 241 - - (482) - 482 -
Gas and diesel purchases (60) (13) - - (74) (29) (15) - - (44) (53) (26) - - (79)
Gas storage costs 15 - - - 15 (132) - - - (132) (139) - - - (139)
Carbon emissions costs (29) (4) - - (33) (12) (6) - - (18) (26) (11) - - (37)
Generation transmission & levies (14) - - - (14) (14) - - - (14) (27) - - - (27)
Electricity networks, levies & meter costs - fixed price (31) (225) - - (256) (32) (218) - - (250) (59) (423) - - (482)
Electricity networks, levies & meter costs - pass through (1) - - - (1) (1) - - - (1) (2) - - - (2)
Gas networks, transmission, meter & service costs (3) (26) - - (29) (3) (24) - - (27) (5) (45) - - (50)
Geothermal service costs (2) - - - (2) (2) - - - (2) (3) - - - (3)
Broadband costs - (34) - - (34) - (28) - - (28) - (60) - - (60)
Other operating expenses (68) (37) (27) 1 (131) (61) (35) (22) - (118) (121) (69) (44) 1 (233)
Total operating expenses (584) (619) (27) 281 (950) (484) (567) (22) 241 (832) (936) (1,116) (44) 483 (1,613)
Realised gains/(losses) on risk management
derivatives not in a hedge relationship (2) - - - (2) (24) - - - (24) (45) - - - (45)
EBITDAF 383 (1) (27) - 354 159 1 (22) - 137 518 (14) (44) - 460
Depreciation and amortisation
(126)
(111)
(224)
Net interest expense
(20)
(19)
(41)
Change in fair value of financial instruments
5
(17)
(18)
Tax expense
(60)
2
(50)
Profit/(loss) 153 (7) 127
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 2023
Unaudited
6 months ended
31 Dec 2022
Audited
Year ended
30 June 2023
EBITDAF 354 137 460
Tax paid (66) (76) (105)
Change in working capital, net of investing and financing activities (10) (43) (55)
Non-cash items included in EBITDAF (18) 120 120
Net interest paid, excluding capitalised interest (9) (12) (25)
Operating cash flows 251 126 395
Stay-in-business capital expenditure (64) (55) (113)
Operating free cash flow 187 71 282
Proceeds from sale of assets - 4 16
Free cash flow 187 74 298
Operating free cash flow per share (cents) 23.7 9.1 36.0
A4. RELATED PARTY TRANSACTIONS
Contact’s related parties include its Directors, the Leadership Team (LT), Drylandcarbon One Limited Partnership, Forest Partners
Limited Partnership, Kowhai Park I GP Limited, Kowhai Park I LP, Glorit Solar I GP Limited and Glorit Solar I LP.
$m
Unaudited
6 months ended
31 Dec 2023
Unaudited
6 months ended
31 Dec 2022
Audited
Year ended
30 June 2023
Forest Partners Limited Partnership
Capital contributions (2) (4) (12)
Key management personnel
Directors' fees (1) (1) (1)
LT - salary and other short-term benefits (4) (4) (7)
LT - share-based compensation expense (1) (1) (2)
LT salary and other short-term benefits are the cash amount paid in the year. Members of the Directors and LT purchase goods and
services from Contact for domestic purposes. For members of the LT this includes the staff discount available to all eligible
employees.
A5. AGS ONEROUS CONTRACT PROVISION
In FY23, Contact recognised an onerous contract provision relating to the Ahuroa Gas Storage (AGS) contract as the value of the
contract is expected to be less than total contract payments. Contact continues ongoing discussions with Flexgas in relation to the
capacity and operations of the AGS facility.
Contact has reassessed the provision to be $90 million at 31 December 2023. Below table shows the movement of the provision
during the period.
$m
Unaudited
6 months ended
31 Dec 2023
Unaudited
6 months ended
31 Dec 2022
Audited
Year ended
30 June 2023
Opening provision balance 116 - -
Created/reassessment (impacts EBITDAF) (35) 120 114
(Released)/increased (impacts EBITDAF) 7 - (1)
Unwind of discount (impacts Interest) 3 - 3
Closing balance 90 120 116
There is a significant level of judgement involved in estimating the value Contact will obtain from access to AGS storage for the
remainder of the contract term. Key drivers include the total storage capacity of AGS, Contact’s gas storage requirements,
hydrology, future gas and carbon prices, the level of Contact’s contracted sales, and the market supply/demand balance. There is
interrelation between these assumptions. Any changes in one of these assumptions would not occur in isolation and would drive
other changes which could also impact the estimated value.
Sensitivity – AGS onerous contract
Key input Sensitivity
Impact on
provision $m
Estimated value received +10% (16)
-10% 16
Pre-tax discount rate (4.4%) +0.5% 3
-0.5% (3)
Estimated available storage +0.6PJs (9)
-0.6PJs 15
A6. CONTINGENCIES
In the normal course of business, Contact is subject to inquiries, claims and investigations. There are no material matters to disclose
at 31 December 2023.
12 Contact | Interim Financial Statements
Contact | Interim Financial Statements 13
B. Our funding
Notes to the interim financial statements for the six months ended 31 December 2023
B1. SHARE CAPITAL
Number $m
Balance at 1 July 2022 780,638,303 1,955
Share capital issued 2,619,193 21
Balance at 31 December 2022 783,257,496 1,976
Share capital issued 1,705,958 12
Balance at 30 June 2023 784,963,454 1,988
Share capital issued 2,542,748 20
Balance at 31 December 2023 787,506,202 2,008
B2. DIVIDENDS PAID
$m Cents per share
Unaudited
6 months ended
31 Dec 2023
Unaudited
6 months ended
31 Dec 2022
Audited
Year ended
30 June 2023
2022 Final dividend 21 - 164 164
2023 Interim dividend 14 - - 109
2023 Final dividend 21 165 - -
165 164 273
Comprising:
Cash dividends
150 146 243
Dividend reinvestment plan 15 18 30
On 16 February 2023 the Board declared an interim dividend of 14 cents per share to be paid on 18 March 2024.
B3. BORROWINGS
$m
Unaudited
31 Dec 2023
Unaudited
31 Dec 2022
Audited
30 June 2023
Lease obligations 46 26 49
Drawn bank facilities - 139 -
Commercial paper 250 230 190
Retail bonds 650 350 650
Capital bonds 225 225 225
Export credit agency facility 29 36 32
USPP notes 224 376 377
Australian medium term notes 434 - -
Face value of borrowings 1,858 1,382 1,523
Deferred financing costs (10) (8) (9)
Fair value adjustment on hedged borrowings 47 26 43
Carrying value of borrowings 1,895 1,400 1,556
Current 356 415 384
Non-current 1,539 985 1,172
All borrowings other than leases and bank overdraft are Green Debt Instruments under Contact’s Green Borrowing Programme,
which has been certified by the Climate Bonds Initiative. At 31 December 2023 Contact remains compliant with the requirements
of the programme. Further information is available on the Sustainability section of Contact’s website.
B4. NET INTEREST EXPENSE
$m
Unaudited
6 months ended
31 Dec 2023
Unaudited
6 months ended
31 Dec 2022
Audited
Year ended
30 June 2023
Interest expense on borrowings (50) (32) (76)
Interest expense on finance leases (1) (1) (1)
Unwind of discount on provisions (7) (3) (8)
Unwind of deferred financing costs (1) (1) (2)
Other interest (1) - (2)
Capitalised interest 35 17 44
Interest income 5 1 4
Net interest expense (20) (19) (41)
14 Contact | Interim Financial Statements
Contact | Interim Financial Statements 15
C. Our assets
Notes to the interim financial statements for the six months ended 31 December 2023
C1. PROPERTY, PLANT AND EQUIPMENT AND INTANGIBLE ASSETS
Property, plant and equipment
$m
Unaudited
31 Dec 2023
Unaudited
31 Dec 2022
Audited
30 June 2023
Opening balance 4,615 4,095 4,095
Additions 273 293 723
Disposals (4) (2) (13)
Depreciation charge (113) (93) (189)
Closing balance 4,771 4,293 4,615
The useful economic life of the Stratford Peaker assets have been reduced for accounting purposes following a review of expected
future availability as a result of recent unexpected outages. This has been applied as a change in accounting estimate from 1 July
2023, and results in a $9 million increase to depreciation in the six months ended 31 December 2023.
Contact is in the process of assessing any impact of the Tauhara delay on costs capitalised to the project. Contact will assess the
enduring economic benefit of all such costs prior to finalisation of the FY24 annual financial statements. Any impact would be
immaterial in the context of the cost of the Tauhara project.
Included within property, plant and equipment is $51 million (31 December 2022: $30 million, 30 June 2023: $53 million) of lease
assets with a depreciation charge of $3 million for the six months ended 31 December 2023 (31 December 2022: $2 million, 30
June 2023: $4 million).
Included within additions is capitalised interest of $35 million (31 December 2022: $17 million, 30 June 2023: $44 million) in
relation to, Tauhara, Te Huka Unit 3, and GeoFuture power stations and associated steamfields.
Intangibles
$m
Unaudited
31 Dec 2023
Unaudited
31 Dec 2022
Audited
30 June 2023
Opening balance 235 227 227
Additions 102 75 115
Disposals (6) (15) (72)
Amortisation charge (13) (18) (35)
Closing balance 318 269 235
Current 116 72 33
Non-current 202 197 202
During the period, Contact wrote off:
– $4 million of assets relating to one of the Peaker engines due to recent damage within Property, Plant and Equipment; and
– $4 million of capital work in progress within intangible assets, relating to a Customer Relationship Management system project
which is no longer continuing in the form originally planned.
Contracted capital commitments
$m
Unaudited
31 Dec 2023
Unaudited
31 Dec 2022
Audited
30 June 2023
Contracted capital expenditure 252 479 300
Carbon forward contracts
89 119 124
Closing balance 341 598 424
Due within 12 months 257 478 300
Due beyond 12 months 84 120 124
16 Contact | Interim Financial Statements
Contact | Interim Financial Statements 17
D. Financial risks
Notes to the interim financial statements for the six months ended 31 December 2023
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 valuation processes, valuation techniques, and types of inputs used in the fair value measurements during the period. Refer to the 2023
Integrated Report for information about fair value hierarchy of our inputs.
Unaudited at 31 December 2023 Unaudited at 31 December 2022 Audited at 30 June 2023
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
Notional amount of derivatives 875 658 1,835 15,253 GWh 137 1,799 GWh 575 376 1,225 14,188 GWh 216 1,741 GWh 875 376 1,585 14,128 GWh 176 1,953 GWh
Maturity years 2025-29 2026-31 2024-31 2024-39 2024-26 2024-28 2025-29 2024-28 2023-29 2023-39 2023-26 2023-28 2025-29 2024-28 2024-31 2024-39 2024-26 2024-28
Average rate/price (P) 5.6% Below (P) 3.6% (F) $107/MWh Below (F) $152/MWh (P) 6.3% Below (P) 2.9% (F) $101/MWh Below (F) $146/MWh (P) 6.1% Below (P) 3.5% (F) $104/MWh Below (F) $144/MWh
(R) 5.3% Below (R) 4.1% (S) $131/MWh Below (S) $165/MWh (R) 5.1% Below (R) 4.8% (S) $126/MWh Below (S) $178/MWh (R) 5.4% Below (R) 4.6% (S) $122/MWh Below (S) $134/MWh
Fair value of derivatives - asset 15 58 37 17 - 24 151 - 57 57 4 2 34 154 2 74 55 78 3 26 239
Fair value of derivatives - liability (20) (9) (27) (218) (4) (37) (316) (26) (8) - (207) (3) (74) (318) (29) (7) (2) (152) (4) (46) (242)
Carrying value of hedged borrowings (867) (708) - - - - (1,575) (545) (252) - - - - (797) (845) (445) - - - -
(1,290)
Fair value adjustments to borrowings 4 (51) - - - - (47) 26 (52) - - - - (26) 26 (69) - - - - (43)
Unrealised gains(losses) below EBITDAF - 2 2 - - 4 7 - - 5 - - (11) (6) (1) - 8 - - 2 9
Realised gains/(losses) below EBITDAF - - - - - (2) (2) - - - - - (11) (11) - - - - - (27) (27)
Realised gains/(losses) within EBITDAF - - - - - (2) (2) - - - - - (24) (24) - - - - - (45) (45)
Total change in fair value of financial
instruments recognised in profit/(loss) - 2 2 - - - 3 - - 5 - - (47) (42) (1) - 8 - - (70) (63)
Hedge effectiveness recognised in OCI - (2) (44) (98) (4) - (148) - (2) 19 (77) (1) - (61) - - 12 14 (1) - 25
Amounts reclassified from OCI to
profit/(loss) or balance sheet - - - (29) 1 - (28) - - - 26 1 - 27 - - - 61 2 - 63
Amortisation of hedge reserve balance - - - 4 - - 4 (5) - - (5) 11 11
Deferred tax - 1 12 21 - 13 47 - 1 (5) 16 - (3) 9 - - (4) 4 (26) (26)
Total change in hedge reserves - (1) (32) (102) (3) 13 (125) - (1) 14 (40) - (3) (30) - - 8 90 1 (26) 73
Initial premium recognised in trade and
other receivables - - - - - 3 3 - - - - - (20)
(20) - - - - - (13) (13)
Key: (P) – pay interest, (R) – receive interest, (F) – fixed price, (S) – spot price
CCIRS inputs
Unaudited
31 Dec 2023
Unaudited
31 Dec 2022
Audited
30 June 2023
USD AUD USD AUD USD AUD
Pay interest NZ 6.5% NZ 5.7% NZ 7.2% - NZ 7.2% -
Pay principal USD 0.75 AUD 0.92 USD 0.75 - USD 0.75 -
Receive interest US 4.3% AUD 6.4% US 4.2% - US 4.2% -
Receive principal USD 0.61 AUD 0.92 USD 0.61 - USD 0.61 -
Foreign exchange contract inputs
Unaudited
31 Dec 2023
Unaudited
31 Dec 2022
Audited
30 June 2023
Unaudited
30 June 2023
Currency
Average
fixed rate Spot rate
Average
fixed rate Spot rate
Average
fixed rate Spot rate
Average
fixed rate Spot rate
AUD 0.92 0.93 0.91 0.93 0.91 0.92 0.91 0.92
USD 0.61 0.61 0.63 0.64 0.62 0.61 0.62 0.61
EUR 0.56 0.57 0.57 0.59 0.56 0.56 0.56 0.56
JPY 83.07 89.22 79.10 83.27 79.51 88.42 79.51 88.42
18 Contact | Interim Financial Statements
Contact | Interim Financial Statements 19
To the shareholders of Contact Energy Limited
Report on the review interim financial statements
11
Conclusion
We have reviewed the interim financial statements of Contact
Energy Limited (the “Company”) and its subsidiaries (together
“the Group”) on pages 2 to 17 which comprise the consolidated
statement of financial position as at 31 December 2023, and the
consolidated statement of comprehensive income, consolidated
statement of changes in equity and consolidated 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 2023, 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 and other
assurance services relating to the Company’s Global Reporting
Initiative disclosures, greenhouse gas emissions reporting and
Green Borrowings Programme reporting. 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
16 February 2024
Corporate directory
Board of Directors
Robert McDonald (Chair)
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 Experience 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
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
Company secretary
Kirsten Clayton
General Counsel and Company Secretary
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
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 2023
Previous Reporting Period 6 months to 31 December 2022
Currency NZD
Amount (000s) Percentage change
Revenue from continuing
operations
1,306,309 31.4%
Total Revenue 1,306,309 31.4%
Net profit/(loss) from
continuing operations
153,463 2232.8%
Total net profit/(loss) 153,463 2232.8%
Interim/Final Dividend
Amount per Quoted Equity
Security
$0.14000000
Imputed amount per Quoted
Equity Security
$0.04666667
Record Date 27/02/2024
Dividend Payment Date 18/03/2024
Current period Prior comparable period
Net tangible assets per
Quoted Equity Security
$2.74 $2.78
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
19/02/2024
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 27/02/2024
Ex-Date (one business day before the
Record Date)
26/02/2024
Payment date (and allotment date for
DRP)
18/03/2024
Total monies associated with the
distribution
$110,250,868
(787,506,202 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
26/02/2024 01/03/2024
Date strike price to be announced (if
not available at this time)
07/03/2024
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
28/02/2024
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
19/02/2024
---
1
2024 interim results
presentation
19 February 2024
Six months ended 31 December 2023
2
Disclaimer and important information
While all reasonable care has been taken in compiling this presentation, neither Contact
nor any of its directors, employees, shareholders nor any other person gives any
representation as to the accuracy or completeness of this information or accepts any
liability for any errors or omissions.
This presentation may contain certain forward-looking statements with respect to a
variety of matters. All such forward-looking statements involve known and unknown risks,
significant uncertainties, assumptions, contingencies, and other factors, many of which
are outside the control of Contact, which may cause the actual results or performance of
Contact to be materially different from any future results or performance expressed or
implied by such forward-looking statements. Such forward-looking statements speak only
as of the date of this presentation. Except as required by law or regulation (including the
NZX Listing Rules and the ASX Listing Rules), Contact undertakes no obligation to
update these forward-looking statements for events or circumstances that occur
subsequent to the date of this presentation or to update or keep current any of the
information contained herein. Any estimates or projections as to events that may occur in
the future (including projections of revenue, expense, net income and performance) are
based upon the best judgement of Contact from the information available as of the date
of this presentation.
EBITDAF, free cash flow and operating free cash flow are financial measures that are
“non-GAAP (generally accepted accounting practice) financial information” under
Guidance Note 2017: ‘Disclosing non-GAAP financial information’ published by the New
Zealand Financial Markets Authority, “non-IFRS financial information” under ASIC
Regulatory Guide 230: ‘Disclosing non-IFRS financial information’ and “non-GAAP
financial measures” within the meaning of Regulation G under the U.S. Exchange Act of
1934.
Such financial information and financial measures (including EBITDAF, free cash flow
and operating free cash flow) do not have standardised meanings prescribed under New
Zealand equivalents to International Financial Reporting Standards (“NZ IFRS”),
Australian Accounting Standards (“AAS”) or International Financial Reporting Standards
(“IFRS”) and therefore, may not be comparable to similarly titled measures presented by
other entities, and should not be construed as an alternative to other financial measures
determined in accordance with NZ IFRS, AAS or IFRS accounting practice) measures.
Information regarding the usefulness, calculation and reconciliation of these measures is
provided in the supporting material.
This presentation does not constitute financial or investment advice. This presentation
does not constitute an offer to sell, or a solicitation of an offer to buy, Contact securities
and may not be relied on in connection with any purchase of a Contact security.
Numbers in the presentation have not all been rounded and might not appear to add.
All references to $ are New Zealand dollar unless stated otherwise.
Alltrademarks, service marks andcompany namesare thepropertyoftheir respective
owners. All company, product and service names used in this presentation are for
identification purposes only. Use of these names, trademarks and brands does not imply
endorsement or that they are or will be customers of Contact and reflects public
announcements of intention only.
3
1H24 highlights and market update / Mike Fuge, CEO 4 - 13
Financial results and outlook / Dorian Devers, CFO 14 - 28
Supporting materials 30 - 41
2
3
1
Agenda
4
1
The onerous contract provision for AGS is assessed every 6 months in line with NZ
IAS 37. In 1H24 there has been a net provision release resulting in impacts of $29m
EBITDAF and $19m profit after tax and interest. Underlying performance excludes
these impacts. All variances and commentary reflect movements in underlying
performance.
Six months ended 31
December 2023 (1H24)
Six months ended 31
December 2022 (1H23)
Underlying
1
ReportedAgainst underlying
EBITDAF
2
$325m$354m↑26% from $257m
Profit$134m$153m↑70% from $79m
Profit per share17.2 c19.5 c↑70% from 10.1c
Operating free cash
flow
3
$187m↑163% from $71m
Operating free cash flow
per share
3
23.7 c↑162% from 9.1c
Dividend declared$110m→$110m
Dividend declared per
share
14 c→14.0 c
Stay-in-business(SIB)
capital expenditure
(cash)
$64m↑16% from $55m
Growth capital
expenditure (cash)
4
$233m↑7% from $217m
A return to hydro volatility categorised the operating
conditions in 1H24. The market observed:
•High inflows and soft wholesale spot prices
through July and August.
•Higher spot wholesale pricing as inflows reduced,
particularly in the second quarter.
•Higher thermal generation compared to 1H23,
which had highest inflows in post-market history.
Summary of key financial performance measures
Underlying performance strength
•High contracted sales volumes in
anticipation of Tauhara coming online and a
strong starting fuel position.
•Thermal generation and some acquired
generation required to meet sales position.
•Mitigations in place for the impacts of
Tauhara delay.
•Channel pricing aligned closer to the
wholesale market.
Market
2
Refer to slide 38 for a definition and reconciliation of EBITDAF. Contact has made
reclassifications to better align with IFRIC guidance on IFRS 9 resulting in realised gains/losses
from market derivatives not in a hedge relationship (includes market making activity) no longer
being reported in operating income (EBITDAF). 1H23 figures restated accordingly.
3
Refer to slide 23 for a reconciliation of
operating free cash flow.
4
Includes capitalised interest.
5
As indicated in November 2022, updated
for inflation.
Focus on delivering geothermal developments and supporting security of supply
1H24
•Lines cost increases from 1 April 2024.
•Disappointing results from Maui drilling campaign
factoring into expected future gas availability.
•Pricing volatility increasing, particularly in peak
periods, as intermittent generation comes online.
•Rising thermal fixed costs at ageing thermal plants
will need to be recovered over less generation and
will factor into risk management pricing.
•Increases to wind costs appear to be structural.
•Conditions support a view of long-term wholesale
prices of at least $110-120/MWh (2024 real).
5
Medium term
•TCC outage brought forward and completed
in December 2023. Expect to
decommission TCC at end of 2024.
•Expect Peaker GT22 to return to service
before winter 2024.
•Commissioning of Tauhara and Te Huka
geothermal plants in Q3 and Q4 of 2024 will
add 1.9TWh of new renewable output to the
portfolio annually once at full capacity.
•Recognising a net $29 million provision
release within EBITDAF for Ahuroa Gas
Storage facility (AGS) onerous contract.
1
5
Key strategic highlights from 1H24
At Tauhara, re-construction of the steam
separation plant is near complete. Te
Huka 3 construction proceeding in line
with expectations.
Drilling, advanced steamfield design and
tendering progressed to prepare for
GeoFuture final investment decision
(FID) in 2024.
1
Advanced stages of preparation for a JV
FID on Kōwhai Park in 2024.
1
Consent lodged for a potential ~300 MW
Southland wind project under fast-track
process.
Emissions intensity from thermal
generation down ~30% on 1H23
driven largely by the closure of Te
Rapa on 30 June 2023.
Assessment of 100MW battery at
Glenbrook
2
has been advanced
ahead of FID in 2024.
1
TCC decommissioning expected at
end of 2024.
1
Constructive negotiations with
Rio Tinto have re-enforced
Contact’s long-held view that a
new long-term agreement for the
supply of electricity to NZAS
appears likely.
Released a request for proposals
seeking strategic partnership to
commercialise food-grade quality
geothermal CO
2.
Objective
1H24
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
Expansion of telecommunications
offering with introduction of Contact
Mobile.
Total closing connections up by 20,000
on 1H23, driven primarily by broadband
and prioritising residential connection
growth within a target channel sales
volume.
Expansion of time of use offerings with
the launch of Good Weekends.
Energy Retailer of the Year finalist
(for the second consecutive year).
1
Calendar year references.
2
Remains subject to consent.
6
De-risking investment in new renewable generation, contributing to energy security and supporting
growth and decarbonisation of the New Zealand economy
A new long-term deal for NZAS would
support the decarbonisation of New Zealand
✓Constructive negotiations with Rio Tinto have re-
enforced Contact’s long-held view that NZAS
appears likely to stay.
✓Contact expects a new agreement to:
▪Be long-term;
▪At a fair price, materially above the current
pricing; and
▪Include demand response (dry-year risk
mitigation).
✓Would create market certainty, de-risking investment
in new renewable generation.
✓Having a large-scale demand response participant
would contribute to dry-year risk mitigation in a
decarbonising market.
Negotiations progressing
Anticipated sector outcomes
Contact has been expecting NZAS to continue operations at Tiwai Point and has been managing its portfolio with that outcome in sight.
The smelter is valuable to New Zealand as a major exporter and its continued operation would contribute to economic growth.
It is highly carbon efficient in its production of premium aluminium, and a major employer and contributor to the Southland economy.
▪Bilateral electricity supply negotiations.
▪Multiple stakeholders with a range of interests.
▪Any agreement can be expected to be conditional on
third-parties.
Complexities
7
Geothermal investment programme update
Supporting the decarbonisation of New Zealand by building world class geothermal power stations
Te Huka 3
Tauhara
GeoFuture
3
Size (TWh p.a)
Online date
Spend to date (to 31 Dec)
1
Committed spend
1
FID date
Total expected project cost
Project progress (at 31 Dec)
1.4
2
0.4
1.4
4
Q3 2024
Q4 2024
2H 2026
Feb 2021
Aug 2022
1H 2024
98%
Pre-FID development
75%
$804m
$213m $31m
$920m
$300m$114m
5
$920m
$300m
$5.3 – 5.7m/MW
6
3
Subject to final investment decision (FID).
4
Based on mid-point of 160-180MW indicative capacity range. Represents a net uplift of 0.4TWh per annum following the closure of Wairākei plants.
5
Approved pre-FID development costs. Contact has been undertaking drilling from September 2023 and advancing steam-field design.
6
Range as indicated in May 2023. Currently in an active tender process for GeoFuture.
Note: Calendar year references
1
Includes sunk costs. Excludes capitalised interest.
2
Output at full 174MW capacity after additional steam plant remediation to be undertaken during
first planned outage. Initial planned capacity of around 152MW expected at online date.
8
Operationalised the higher consented fluid take
at Wairākei field (5kt per day) translating to a
50GWh p.a. uplift in average geothermal
generation (before new developments online).
TCC planned outage brought forward and
completed in December 2023 with additional
operating hours approved.
Contact has worked to accelerate the return of
its spare peaker engine. Now expecting GT22 to
be back in service for winter 2024 (expected
return May 2024).
Included in DJSI Asia Pacific for the second
consecutive year, moving into the number
one ranking of participating NZ companies.
Sustainability Leadership winner in the
Deloitte Top 200 Awards.
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
Wellbeing Award winner, NZ Energy
Excellence Awards, for Contact’s
Grow Your Whanau Policy.
Enhanced our Health & Safety toolkit
with the launch of the Roam App and
Protect@Contact website.
Objective
1H24
highlights
1H24 delivery supported by enablers
9
National electricity demand
Source: EMI, Contact.
Does not include NZAS
National electricity demand (TWh)
Regional
change (%)
1H24 vs 1H23
Source: EMI, Contact
Market demand
2.5
2.62.6
2.5
2.5
2.5
2.5
5.3
5.0
5.3
5.4
5.2
5.5
5.6
13.4
13.4
13.5
13.4
13.3
13.2
13.3
1H181H191H201H211H221H23 1H24
North Island
South Island (ex NZAS)
NZAS
21.2
21.0
21.4
21.3
21.1
21.2
21.4
0%
+1%
New Zealand electricity demand was up ~1% on 1H23
Total national electricity demand
increased by 0.15 TWh (1% from
1H23).
•Dry conditions increased demand
at major irrigation nodes in Huntly
and South Canterbury, particularly
on the Lower Waitaki plains.
•Temperature did not have a
significant impact on demand as a
cold August was partly offset by
warmer surrounding months.
•East Coast regional demand was
down 23% with Pan Pac’s
Whirinaki site closed until further
notice due to impacts from
Cyclone Gabrielle.
•Normalising for weather and Pan
Pac, which largely offset
eachother, demand growth came
in at just over ~1%.
(1%)
14%
(2%)
(1%)
2%
(1%)
11%
1%
2%
0%
1%
6%
2%
0%
1%
5%
2%
(23%)
2%
10
Hydro generation was down
11% on 1H23, largely due to
1H23 being an unusually wet
period with nationwide inflows
at the 96th percentile of historic.
1H24 saw a return to hydro
volatility and a reduction in
national storage levels.
Impacts included:
•
Higher spot wholesale
prices.
•
Need for thermal generation.
•
Higher industry carbon
emissions.
Wind generation has stepped
up with Turitea online
throughout 1H24 and initial
generation from Kaiwera Downs
and Harapaki from October and
November 2023 respectively.
Generation by type (TWh)
At the onset of 1H24, hydro storage levels started notably higher than the historical mean but dropped significantly
due to low inflows into both North and South Island catchments. National hydro storage levels were lower on
average, compared to 1H23, increasing the market’s reliance on thermal generation.
Source: EMI & MBIE
Source: NZX
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
Dec-
21
Jul-
22
Dec-
22
Jul-
23
Dec-
23
Mean
Actual
1H24
1H23
Storage
TWh
National hydro storage
Carbon emissions (mT)
1
Carbon emissions for 1H24 Oct-Dec quarter has been estimated using historic conversion rates with actual generation data.
Hydrology significantly impacted generation mix
Fuel supply
El Niño sequence saw low hydro inflows increasing the need for thermal generation; wind farms power up
2H232H22
The increase in carbon emissions of 0.7mT (70%) CO2-e was due to the
increase in coal and gas generation year on year.
2.2
1.7
1.6
0.9
1.3
1.8
3.6
3.7
3.7
12.9
14.1
12.6
0.2
1.3
2.1
1.3
1.5
0.4
1H221H231H24
Gas
Coal
Hydro
Geothermal
Wind
Other unidentified
generation
22.1
22.3
22.4
1.71.01.7
1
11
11
Aluminium
Demand
Short-term external factors that
can influence the market
Changes as at 31 December 2023
in comparison to 31 December 2022
Short-term
wholesale
electricity
prices
Operating constraints
remain at Ahuroa Gas
Storage Facility (AGS).
Gas field delivery
forecasts continue to
decline.
Carbon prices down 10%
to $69 per unit (NZU).
Although the December
NZU carbon auction
failed, remaining units will
not roll into 2024 (unlike
previous auctions).
Methanol pricing at
US$323/t
(down 7%).
Additional gas available
for the electricity sector
through the
Methanex outage.
Demand was
up ~1%
year on year
Aluminium prices remained
largely flat (+$10/t, up 0.3%)
Decrease in coal prices
(-US$258/t, down 64%).
Genesis Market Security
Option (MSO) estimated
price $255/MWh
1
,
down 39%.
Forward wholesale pricing continues to reflect
high fuel cost and availability risk
Controlled storage at
~80% of mean (~455
GWh below mean) at
the end of the period.
Wholesale and futures electricity pricing ($/MWh)
Wholesale market
0
50
100
150
200
250
300
10 year
average
spot price =
$103 /MWh
Dec-
12
Dec-
13
Dec-
14
Dec-
15
Dec-
16
Dec-
17
Dec-
18
Dec-
19
Dec-
20
Dec-
21
Dec-
22
Dec-
23
Long-dated futures (>12 months)
Short-dated futures (<12 months)
Monthly average spot price
Source: EMI wholesale pricing
1
Source: Forsyth Barr January 2024 Power Points
Fundamental requirement for thermal generation to support a hydro dominated system. Expected future marginal
thermal costs and higher renewable development costs supporting the forward electricity price path.
12
12
•Competition remains intense despite sustained high wholesale futures prices.
Market churn continues to reflect this with switching at 19%.
•New buildings contributed to a continued ~1% p.a. growth in ICPs.
•Tier 1 retailers have a seen a 0.5% increase in market share to ~85% in
December 2023 (84% December 2021). Genesis’s growth is partially driven by
the acquisition of Ecotricity in Feb 2022.
•Tier 2 retailer growth rates have slowed as they have repriced to rising input
costs (energy and networks), resulting in a 1% decline in market share to
~15% (16% December-21) but some (Flick, 2degrees) are growing strongly.
•2degrees and Vocus merged on 1 June 2022 becoming the third largest telco,
while also providing energyproducts. Since 31 December 2021, 2degrees has
grown connections by 10k (25%). Flick Electric returned to strong growth in
2023, +11k connections (44%) on the prior year.
•Contact electricity connections +3k from December 2021 to December 2023
resulting in a 19% market share. Contact had the third lowest churn over the
two year period.
Change in customer electricity connections (000s)
31 December 2021 – 31 December 2023
2yr % change2yr ICP delta (1000s)
Retail electricity tariff changes
1
(c/ kWh)
Tier 2: +1.4k connections
•Increasing wholesale energy and, more recently, network costs have
resulted in a lift in Residential electricity tariffs with the compound annual
growth rate of 3% across the last five years to November 2023.
•Average tariff increases for the year to November 2023 of 3.7%
werematerially below consumer price inflation (~4.7%)
3
, with households
largely insulated from increasinginput costs due to retailers’ longer-term
view of pricing that rides through short-term volatility.
•Input cost pressure for retailers is expected to remain with ongoing elevated
wholesale prices and significant network cost increases pending:
•1 April 2024 inflation adjustments.
•1 April 2025 price regulation reset.
Retailers’ pricing will need to increase to recover these rising costs.
12 months
ended:
Tier 1: +64k connections
Source: EMI
Source: MBIE
12%
1%
-5%
3%
2%
-12%
-3%
-9%
25%
11%
-20
-10
0
10
20
50
60
GenesisManawaNovaContactPulse
48%
FlickMercury/
Trust
Power
Electric
Kiwi
2degrees/
Vocus
MeridianOther
18.1
19.4
20.1
20.9
21.8
12.1
11.1
11.3
11.6
11.9
Nov-19Nov-20Nov-21Nov-22Nov-23
30.2
30.5
31.5
32.5
33.7
+3%
2
Differences in retail strategies apparent
Retail electricity market
Reflects range of views on the value of retail as a channel; Rising pass-through costs on the horizon
Lines (c/kWh)Energy & Other (c/kWh)
1
Inclusive of GST
2
Compound annual growth rate
3
Stats NZ CPI index increase in the 12 months to December 2023.
13
Topical regulatory matters
Security of supplyReconsideration of energy
policy priorities
Theme
Contact Approach
Timing
Electricity Price
pressures
Lines assets regulation /
investment
Resource management
reform
Maintaining security of supply is the
top priority of the new government.
Industry, Transpower and the EA
paying close attention to capacity this
year and beyond.
Work on Lake Onslow has ceased, and
there is a wider reconsideration of
energy policy priorities.We expect
increased focus on market-driven
solutions.
Work on an energy strategy likely to
continue in some form, but with an
increased focus on energy security.
NZ Energy Strategy due for
completion by end of 2024.
Engagement ongoing.
Contact targeting 10.3TWh of
renewables and 100MW battery by
FY27.
Investment in new baseload
renewables, storage and demand
response.
Operateour assets in a way to avoid
contributing to any supply shortage.
Contact’s focus on building new renewable generation, flexible storage and customer-focused demand response
solutions is well aligned with the political focus on electrifying NZ’s economy while maintaining security of supply
Working with electricity industry to
establish near-term actions to
implement the plan set out in BCG’s
report “the Future is Electric”.
Orderly decarbonisation of own
portfolio. Focus on energy security
and affordability.
...
Sufficient line capacity is critical to
decarbonisation, however, must be
balanced against the impact on
consumers.
Recommends
regulatory changes to
reduce connection costs aiding
electrification projects.
Working with industry groups and
communicating with customers on the
drivers of price increases.
Focus on demand flex and TOU
1
plans
to help customers better manage their
energy use and resulting costs.
Continuing our focus on energy
wellbeing for those in most need.
Draft decision on 2025-30
revenue caps due in May 2024,
and a final decision in November
2024.
Government has reinstated the RMA
3
and will begin work on a new
replacement Act.
Government refreshing the national
policy statement for renewable
electricity generation (NPS-REG).
New Fast Track legislation to be
introduced in Q1 2024.
Contact has advocated for a
balance between environmental
effects and the need to decarbonise
our economy.
Reinstatement of RMA reduces
disruption and we will engage in the
design of the replacement Act.
Draft NPS-REG looks promising.
.
NPS-REG is part of new
government’s 100-day plan.
RMA replacement Bill will be
proposed as part of 2026 election
campaign.
1
Time of Use
2
Note $22bn refers to opex and capex spend required from 2022 to 2030. Expenditure required on distribution infrastructure out to 2050 is $71bn.
3
Resource Management Act
Government price regulation of EDBs
and Transpower for 2025-30.
BCG report found a need for $22bn
2
of
expenditure on distribution
infrastructure before 2030.
BCG noted a 30% increase in spend
required in 2026-30 relative to 2021-25.
Retail energy prices are facing cost
pressures from increasing government
levies, wholesale energy costs and
lines charges, driven by the 1 April
2025 regulatory reset.
Increased wholesale price volatility is
placing pressure on unhedged energy
intensive industries.
ERANZ/ENA joint work on
communicating price increase
pressures in 1H 2024.
14
Financial
results and
outlook
15
Key themes from the financial results
Uplift in expected and normalised
performance; Expecting $620m
EBITDAF in FY24
Net release of AGS onerous
contract provision
$29m within EBITDAF
Sales channels repricing to better
align with wholesale market;
Retail facing headwinds from
network cost increases
Key indicators re-enforce our view on
long-term wholesale electricity pricing
of $110-120/MWh (2024 real)
1
Thermal assets keep market in
balance; Increasing costs from
ageing assets need to be recovered
1
As indicated in November 2022, updated for inflation.
16
Profit ($m)
Excluding the AGS onerous contract provision, underlying EBITDAF up $68m (26%) reflecting continued
improvement in the alignment of channel pricing to the wholesale market
Profit of $134m for 1H24 (underlying)
EBITDAF ($m)
Increase in
thermal efficiency
due to the closure
of Te Rapa and a
high proportion of
TCC generation
Wholesale prices
saw higher
realised CFD and
merchant sales
Renewables
down 91GWh
with 137GWh
decrease in hydro
generation partly
offset by 47GWh
geothermal uplift
Fixed costs
higher due to
inflation impacts
and growth
431
1H24 results
Net interest
costs
EBITDAF
1
Depreciation
& Amortisation
Tax
1H23
EBITDAF
1
1. Renewables
1H24 EBITDAF
before onerous
contract provision
2. Net Volume
2
Reduced steam
revenue post Te
Rapa closure,
partly offset by an
increase in gas
gross margin
1H24 profit
before
onerous
contract
provision
Back-out: Onerous contract provision after tax
Reported profit
86
153
68
22
-19
-7
-15
2
-21
79
134
+55
Increased
contracted sales
volumes were
largely backed by
thermal
generation due to
Tauhara delay
6
1
Contact has made reclassifications to better align with IFRIC guidance on IFRS 9 resulting in realised gains/losses from market derivatives not in a hedge relationship (includes market making activity) no longer being reported in operating income
(EBITDAF). 1H23 figures restated accordingly.
Note: All figures are exclusive of the impacts of the onerous contract provision for AGS. Impacts of the onerous contract are as follows, EBITDAF (+$29m), interest (-$3m), tax (-$7m), NOPAT (+$19m).
3. Market
Channel Pricing
5. Gas, carbon
and acquired
generation price
6.Other income
7.Fixed costs
137
120
57
39
354
-11
-10
18
-9
-9
-8
-29
257
325
+68
4.Long Term
Chanel Pricing
Retail pricing
aligning to recoup
energy and pass-
through costs
5
Back-out: Onerous contract provision before tax
Reported EBITDAF
8.One-off write
offs
8
One-off write offs
relate to Peaker
damage
(-$4.0m) & CRM
system project
not continuing as
originally planned
(-$3.9m)
7
1H23 profit
before
onerous
contract
provision
FV of financial
instruments
17
Wholesale EBITDAF
1
(underlying, $m)
Retail EBITDAF ($m)
Corporate / unallocated costs ($m)
Business performance by segment
EBITDAF up by $68m (underlying)
Refer to slides 18 - 20
Refer to slide 21
279
354
67
126
17
1H23Generation
costs
(including
acquired
generation)
Total
contracted
revenue
Trading,
merchant
revenue
and losses
1H24
354
+75
1
-1
40
1H23
0
Electricity
Volumes
45
Electricity
Prices
5
Other
products
2
2
Opex1H24
-2
Electricity gross margin
(-$5m)
Electricity
and network
cost inflation
Price recovery
2
Other products includes retail gas and broadband gross margins and gains
on sale of legacy meter assets.
1H24 results: Segmental performance
-22
-27
1H23
2
1H23
One offs
4
1H24
One offs
1
Inflation
(4.7%)
3
3
Growth1H24
-5
1
Simply and Western included within Wholesale EBITDAF.
Underlying EBITDAF is shown excluding $29m net release of the onerous contract
provision for AGS. Contact has made reclassifications to better align with IFRIC guidance
on IFRS 9 resulting in realised gains/losses from market derivatives not in a hedge
relationship (includes market making activity) no longer being reported in operating
income (EBITDAF). 1H23 figures restated accordingly.
One-off movements from 1H23 included execution programme
setup costs and BCG industry report ($2m). 1H24 one-off
movement is a write-off relating to the CRM system project not
continuing as originally planned.
3
Stats NZ CPI increase in the 12 months to
December 2023.
18
Electricity generated or acquired (GWh)
Costs up $67m on increased thermal and acquired generation volumes to back higher sales position
1H24
1H23
Electricity generated or acquired costs ($m)
Generation costs
1H24 results: Wholesale business
Gas and diesel
Acquired
Thermal
Renewable
Gas storage
Carbon costs
Electricity and gas
transmission and levies
Other operating costs
Generation volumes
•
Hydro generation of 1,916GWh was down 137GWh (7%) on
1H23 following low inflows.
•
Geothermal generation was up 47GWh (3%) on 1H23,
~34GWh (73%) of the uplift is attributable to the increased
consented mass take from the Wairākei steam field (from
245,000 to 250,000 t/d).
•
1H24 thermal generation volumes were 526GWh (181%)
higher than 1H23 as depleting hydro storage and the delay to
Tauhara’s online date meant Contact’s increased sales position
was partly backed by thermal generation.
Costs
•
Renewable generation costs were up $6m (11%) through a
combination of higher insurance, rates, higher geothermal
carbon costs and generalinflationary pressures.
•
Thermal generation costs, excluding the net release of the
onerous contract provision AGS ($29m), were up $49m (78%)
on increased thermal volumes.
•
Thermal fuel costs dropped to $96.40/MWh (1H23:
$120.10/MWh) largely due to improved thermal efficiency
following the closure of Te Rapa and a high proportion of TCC
generation (1H23: 11.8 TJ/MWh, 1H24: 8.2 TJ/MWh). This was
slightly offset by increased gas costs (1H23: $7.9/GJ, 1H24:
$8.3/GJ) and higher unit price of carbon (1H23 $43/unit, 1H24
$59/unit).
1,605
1,652
2,053
1,916
291
817
131
239
1H231H24
Acquired
Thermal
Hydro
Geothermal
4,081
4,624
54
59
54
16
60
17
63
28
112
56
16
12
30
29
12
14
16
30
5
3
138138
205205
+67
93%
Renewable % of
own generation
81%
$44.4/MWh
$33.8/MWh
*Gas storage costs exclude the 1H24 $29m net release within EBITDAF of the onerous
contract provision for AGS.
Development
Acquired generation
costs
19
1,989GWh
$140.6/MWh
Contracted
revenue ($m)
High stored fuel balances at the beginning of 1H24 paired with the anticipation of Tauhara coming online
drove an increase in contracted sales volumes
1,269GWh
$139.7/MWh
+0GWh
+$19.6MWh
+697GWh
+$32.1/MWh
•Fixed price variable volume electricity sales to the Retail segment and C&I customers
ended 46 GWh lower than 1H23 (-$6m). The volume shift is attributed to C&I, with the CFD
channel prioritised over C&I in 1H24 and Retail volumes held steady.
•Pricing to C&I was up $1.2/MWh, broadly in line with last year, with preference
given to CFDs in calendar 2023.
•Pricing to the Retail channel up $19.6/MWh to $140.6/MWh reflecting higher
wholesale prices over the three preceding years.
•Strategic fixed price sales were 122GWh lower than 1H23 (-$8m), reflecting the roll off of
the Fonterra contract following the closure of Te Rapa. Pricing of strategic fixed priced sales
is down $4/MWh as inflationary adjustments to long-term sales were not enough to offset
the mix change from proportionally higher NZAS volume.
•CFD sales volumes were up by 697GWh (+$75m) due to the anticipation of Tauhara
coming online. Prices were up by $32.1/MWh reflecting low hydro inflows over the period
(+$41m).
•Steam sales down on the closure of Te Rapa (-$16.8m).
•Other income was higher (+$4m) mainly due to premiums received from the CfD swaption
deal with Meridian over the period.
Wholesale contracted revenue
24
543GWh
$135.3/MWh
-46GWh
+$1.2/MWh
241
280
79
73
61
177
38
30
19
0
-5
1H23
1
4
-6
1H24
Other net income
Steam sales
Strategic fixed price sales
CFD sales
C&I net price
Retail segment sales
C&I channel
and decarbonisation
support costs
433
559
2
+126
1H24 results: Wholesale business
602GWh
$49.2/MWh
-122Wh
-$4.0/MWh
Year-on-year
changes to
volume and price
1H24 volumes
and price
1
Contact has made reclassifications to better align with IFRIC guidance on IFRS 9 resulting in realised gains/losses from market derivatives not in a hedge relationship (includes market making activity) no longer being reported in operating
income (EBITDAF). 1H23 figures restated accordingly.
20
Trading EBITDAF ($m)Long / short position (GWh)
$131.9/MWh
5.1%
($6.7 / MWh)
13.0%
($7.5/ MWh)
•In 1H24, merchant length offset
location losses. This is in line with
guidance which assumed mean
hydro conditions and that any
merchant length and location
losses would offset.
•Compares to 1H23 where
exceptionally high national inflows
led to soft wholesale prices and
higher location losses relative to
merchant length.
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
12
29
-29
-29
1H231H24
-17
0
210
223
-3,827
3,827
1H23
4,402
-4,402
1H24
1H24 results: Wholesale business
LWAP/
GWAP
losses
1
Source: EMI
Merchant
sales
$/MWh
21
1
Retail business performance
EBITDAF ($m)
Managing through elevated wholesale input costs while growing market share through a multi-product strategy
Revenue & Tariff
1
($m)
1H241H23Variance
$mTariff¹$m$mTariff
Electricityrevenue
5242804834222
Gas revenue
51374836
Broadband revenue
39733273
Other income
46(2)
Total revenue
61856850
Contract Asset
(closing)
46(2)
# of connections
(closing)
2
591k571k20k
Electricity
428k423k5k
Gas
70k70k0k
Telecommunications
3
93k78k15k
Cost to
serve/connection
$63$61($2)
1
Tariff is $/MWh for electricity, $/GJ for gas and $ per month per customer
connection for broadband.
2.
Retail connections only, excludes Simply Energy.
3
Includes broadband and mobile connections.
Gross Margin (GM) is Revenue less Cost of Goods (Networks,
meters, levies, energy, carbon and broadband).
1H24 results: Retail business
Retail margins have contracted, driven by sustained high wholesale
prices.
•Retail EBITDAF decreased by $2m on 1H23 largely driven by the
$45m increase in electricity costs that were not fully passed through to
customers.
The Retail business has continued to insulate customers from significant
input cost rises with the forecast annual tariff increase largely in line with
consumer price inflation.
•The average Retail tariff increased on 1H23 reflecting significant
customers rolling off fixed term contracts and targeted retail price rises
to partially offset rising wholesale and network cost increases.
•Around 84% of customers received a price increase in the last 12
months.
•Retail energy tariffs will need to continue to rise to recover the ongoing
elevated wholesale prices and significant network cost increases due
to the 1 April 2025 price regulation reset.
•Contact remains focused on supporting our customers in energy
hardship through ERANZ, with offerings like ConnectMe and
EnergyMate, and directly with community groups.
Connection growth slowed in 1H24 with an increased focus on input cost
recovery.
•Total connections still +20k on 1H23primarily through continued
growth in broadband.
•Multiproduct customers up 9% on 1H23, driven by Time of Use Good
plans growth with high broadband attachment.
Cost to serve – increased by $2/connection largely driven by timing of
marketing spend and higher bad debt. This was partially offset by
productivity improvements through continued growth in digitised
interactions.
4
5
24
19
3
10
5
2
-35
-37
1H231H24
1
-1
Other income
Gas GM
Electricity GM
Broadband GM
Other operating
expenses
22
Other operating
cost movement
($m)
Base
movement
Non-recurring
•1H23 one-off impacts related to strategic execution set up costs, Contact’s
share of BCG Industry report and cost of retaining Te Rapa employees until
plant closure.
•1H24 one-off impacts represent a write-off from damaged Peaker assets and a
write-off relating to the CRM system upgrade project no longer continuing as
originally planned.
Base movement
•General inflation of 5-6% impacting operating costs. These have been seen
across the business, including labour cost and insurance inflation.
•Headwinds include remaining repair costs relating to Cyclone Gabrielle and
increased level of bad debts from our Retail business.
Growth and sustainability
•$1m incremental investment related to retail connection growth.
•$1m investment in advertising in launching Contact Mobile.
•Operating costs to deliver on strategic growth priorities including;
•Sustainability and furthering ESG outcomes;
•Procurement; and
•Full 6 months of costs from increase in Corporate functions to support
growth activity.
Operating costs up on investments in growth
strategy and cost pressures
Base savings
General cost inflation
Invest in
growth and
sustainability
1H24 results: Operating costs
Headwinds
8
6
3
115
1H23
2
2
Base movement
3
Growth & Sustainability
124
1H24
118
6
132
Non recurring items
23
•Higher underlying EBITDAF on execution of long-term channel price increases.
•Working capital increase was $33m less than in the prior year due to lower levels of gas storage
following higher thermal generation in 1H24 and seasonal movements in net receivable balances.
•Tax paid is down $10m with final FY23 payment being lower than final FY22 payment.
•Stay-in-business capital expenditure (cash) increase of $9m is linked to accelerated spending
identified to support higher asset availability and output as well as an SAP systems upgrade
project. Accelerated SIB capex programme spend in the period totaled $24m.
6 months ended
31 December 2023
(1H24)
6 months ended
31 December 2022
(1H23)
Comparison
against 1H23
EBITDAF (underlying
1
)$325m$257m
1
↑$68m
Workingcapital changes($10m)($43m)↑$33m
Taxpaid($66m)($76m)↑$10m
Interest paid, net of interest capitalised($9m)($12m)↑$3m
SIBcapital expenditure($64m)($55m)↓($9m)
Non-cash items includedin EBITDAF$11m($0m)↑$11m
Operating free cash flow$187m$71m
1
↑$116m
Operating free cash flow per share23.7 c9.1 c
1
↑14.6 c
Cash conversion (OpFCF/EBITDAF)58%28%↑30%
Cash conversion for 1H24 impacted by higher EBITDAF, lower fuel inventory and lower tax payments
Cash flow and capital expenditure
Sources and uses of cash ($m)
1H24: Cash flow
1
Contact has made reclassifications to better align with IFRIC guidance on IFRS 9 resulting in realised gains/losses from market derivatives not in a hedge relationship (includes market making activity) no longer being reported in operating income
(EBITDAF). 1H23 figures restated accordingly.
187
165
134
1
335
15
Sources
2
233
2
Uses
537
537
Cash Movement
Debt drawdown
OpFCF
DRP
Strategic investments / acquisitions
Growth investment
Dividends paid
Realised losses on market derivatives
Financing cost / cost of debt issuance
24
•Face value of borrowings (excl. leases) increased by
$338m to $1,812m from 30 June 2023.
•A Green Australian Medium Term Note (AMTN) was
issued during the half year, this was partly to
refinance a maturing tranche of USPP in December
2023, but also to provide additional funding for the
ongoing capital investment programme.
•All facilities are classified green under Contact’s
sustainable finance framework, and the bank facilities
are sustainably linked with alignment to the
Contact26 strategy to lead the decarbonisation of
New Zealand.
•The KPIs on Contact’s sustainably linked loan for
emissions reductions and DJSI performance were
met for FY23 providing a discount on the borrowing
rate for Contact.
•Contact’s planning aligns with maintaining its
investment grade credit rating. This requires net debt
to EBITDAF to remain below 3.0x over a sustained
period. Point estimate net debt to EBITDAF is
currently 2.6x and Contact’s EBITDAF outlook, DRP
and capacity for additional hybrid bonds provide the
ability to mange this metric effectively.
With market leading sustainable finance principles built on diversified sources of funding
Closing net debt ($m)
Face value of borrowings less cash
Interest rate (%)
Weighted average gross interest
2
on average borrowings
Net debt to EBITDAF (x)
Includes S&P adjustments (prior to FY20, AGS was treated as a lease)
Borrowing maturities ($m)
Average tenor of 6.4 years as at 31 December 2023
Strong balance sheet
1
Includes $112m of collateral held on deposit for margin calls associated with the trading of electricity price derivatives on the ASX.
2
Gross interest includes all interest on borrowings, bank commitment fees and deferred financing costs. Unwind of leases, provisions and capitalised interest not included.
3
Illustrated here on a point basis based on a normalised and expected EBITDAF of $600m.
1,410
990
1,036
774
1,025
1,474
1,812
-274
38
-3
FY18
25
-47
FY19
22
-44
FY20
21
-150
FY21
25
-168
FY22
49
-140
FY23
46
1H24
1
1,445
968
1,014
645
882
1,383
1,584
Lease obligationsBorrowingsCash on hand
4
67
434
225
100
136
350
300
75
75
250
350
FY24
7
FY25
7
FY26
7
FY27
22
4
FY28FY29FY30FY31FY52
182
218
357
625
367
Undrawn bank facilities
Domestic bonds
USPP
NEXI
Capital bonds
AMTN
2.3
2.4
1.2
1.5
2.2
2.6
FY19FY20FY21FY22FY231H24
3
1,207
1,031
963
902
1,329
1,660
5.4%
FY19
5.2%
FY20
5.2%
FY21
5.3%
FY22
5.8%
FY23
6.0%
1H24
Average gross interestAverage gross debt
1H24 results: Key balance sheet metrics
25
87
116
920
220
58
Medium-term capital investment programme
1
Active developments and projects coming to FID in 2024
Indicative
investment sizing –
To be confirmed on
pre-FID projects in
line with market
Growth investment funding strategy
Complementing conventional debt funding and hybrid debt instruments, Contact has a Dividend Reinvestment
Programme that can provide additional equity support
Te Huka 3 (remaining)
Tauhara (remaining)
GeoFuture
Renewables (ex geothermal)
Capitalised interest
Potential sources of funding to FY28
270
880
190
61
Dividend Reinvestment Plan (DRP)
Debt Capacity
Hybrid Credits
Balance from Operating Cash Flow
The DRP draws from expected
available capacity from the
programme where a discount is
offered. Any operating cash flow
in excess of gross dividends
provides another source of
funding.
Commitment to maintaining
S&P investment grade credit
rating continued.
$1,401m$1,401m
1H24 results: Funding strategy
Under construction
2
Pre-FID
Note: All figures in pie charts exclude capitalised interest.
1
Assumes capital calls for associate investments, Dryland Carbon and Forest Partners, as well as realised losses on market derivatives not in a hedge relationship are funded through retained operating cash flow above gross dividends.
2
Remaining under current approvals as at 31 December 2023.
3
Based on ~$950m total project capital ($5.3-5.7m/MW for a 160-180MW capacity plant) less ~$30m pre-FID development costs incurred as at 31 December 2023.
4
Includes one battery and one solar project going to FID in 2024 and ~$5m of pre-FID wind development costs remaining under current approvals.
5
Debt capacity is assessed based on end of FY27 run rate EBITDAF of $815m indicated in May 2023.
3
4
5
Up to 31
December
2023
Remaining
under
current
approvals
Total
Tauhara$804m$116m$920m
TeHuka 3$213m$87m$300m
GeoFuture$31m$83m$114m
Wind$10m$5m$15m
Capitalised
interest
$134m$58m$192m
Total$1,192m$349m$1,541m
Growth capital expenditure ($m)
Ordinary dividends ($m)
Declared
Final dividendInterim dividend
% pay-out of operating free cash flow
Dividend for 1H24
165
163163
164
110
115
109109
109
FY20FY21FY22FY231H24
280
272272
273
110
cps
Interim dividend for 1H24 of 14 cents per share
•Interim dividend of 14 cents per share is imputed to 86% or 12 cents per share for qualifying shareholders.
•Dividend timeline brought forward. Record date of 27 February 2024; payment date of 18 March 2024.
•The NZD/AUD exchange rate used for the payment of Australian dollar dividends will be set on 7 March
2024.
Dividend reinvestment plan (DRP)
•Shareholders will have the option of full, partial or no participation. If a shareholder elects to participate,
they will remain in the plan at the same participation level until they elect to terminate or amend their
participation level.
•There will be no discount offered for the 1H24 dividend and Contact will have the right to terminate or
suspend the plan at any time.
•Dividend reinvestment plan application forms must be in by 28 February 2024 to confirm participation in
the plan.
•Trading period for setting price for DRP is 26 February 2024 to 1 March 2024. DRP strike price will be
announced: 7 March 2024.
97%
72%
82%
97%
39
35
35
14
35
59%
26
27
Sustainable pricing changes drive an uplift
in FY24 expected EBITDAF
10
20
18
FY24 normalised¹
and expected
1H realised hydrology
8
1H realised impairments1H gas and risk
management costs
Sustainable long term
channel pricing movement
FY24 expected
(with mean 2H
hydro conditions)
600
620
¹ See slide 32 for assumptions underpinning FY24 normalised and expected earnings as assessed in August 2023.
EBITDAF ($m)
1H24 actual performance vs. normalised and expected that will not unwind in 2H24
Given the requirement for design and construction remediation of the Tauhara steam separation system, Contact is assessing the economic benefits
of all costs capitalised to the project and will complete this assessment prior to the finalisation of the FY24 results.
Any impact would be immaterial in the context of the Tauhara project. The expected FY24 EBITDAF of $620m does not include this potential impact.
28
Our operational plan
Calendar 2024
Enter new long-term supply
agreement with NZAS.
Tauhara operational Q3 2024
1
.
Te Huka 3 operational Q4 2024
1
.
Final Investment Decision on
BESS (battery).
Grow renewable
development
Decarbonise
our portfolio
Create
outstanding
customer
experiences
Strategic theme
Grow
Demand
Achieve FID for GeoFuture.
Achieve FID for Kōwhai Park solar.
Final Investment Decision (FID) for
C0
2
commercialisation.
Expect to decommission TCC at
end of 2024.
1
Further expansion of “It’s good to be home”
brand position.
What you can expect in the next 12 months
1
Calendar year references.
Expansion of demand flex to retail customers.
29
Questions
30
Supporting
materials
31
Guidance confirmation
Updated
FY24 guidance
1H24 resultChange to prior guidance
Stay in Business Capex
$120m -$130m
1
$64m+$5m
Stay in business accelerated programme (cash)
$55m -$60m$24m-
Stay in business capital expenditure (cash) BAU
$65m -$70m
$40m+$5m
Non-sustained increase relates to emergency repairs at Wairākei
following Cyclone Gabrielle and Peaker GT22 repairs.
Growth capital expenditure (cash)
2
$400m -$500m$233m-
Increase in capitalised interest is offset by reductions in projects due to
timing of spend.
Depreciation and amortisation
$250m -$260m$126m+$20m
Acceleration in Peaker assets and change in useful life for geothermal
plant partially offset by extension of SAP assets.
Net interest (accounting)
$45m -$55m$17m
-$20m
Higher mix of capitalised interest due to the Tauhara delay. Interest rates
reducing and increased interest earned on cash.
Cash interest(in operating cash flow)
$27m -$37m$9m
Cashtaxation
$95m
-
$105m
$66m-
Realised (gains) / losses on market derivatives not in a
hedge relationship
3
$10m -$15m$2m-
Corporate costs
$52m$27m+$4m
Increase is due to one-off write-off of $3.9m relating to the CRM system
project not continuing as originally planned.
Target ordinary dividend per share
Minimum 35 cps14 cps-Conditions precedent for increase in guidance not yet met.
1
FY24 guidance range is gross i.e. before the netting off insurance proceeds of $15m.
2
Growth capital expenditure includes capitalised interest and is based on current Board-approved capital spend.
3
Previously included within EBITDAF (cash).
32
Strategic fixed price600GWh$50/MWh $30m
CFDs1250GWh$140/MWh$175m
C&I650GWh$145/MWh$94m
Retail2,000GWh$144/MWh$288m
Other income³$20m
$608m
Hydro2,030GWh$0/MWh-$0m
Geothermal1,625GWh$5/MWh-$8m
Thermal⁴1,035GWh$120/MWh-$124m
Acquired0GWh$0/MWh-$0m
-$132m
Length⁵$27mTransmission/Storage-$35m
Location losses⁶-$26mOperatingexpenses-$129m
Total$1mTotal-$164m
1H24 assumptions that deliver expected & normalised EBITDAF of $600m over a financial year
EBITDAF reconciliation to 1H24 ($m)
Hydrology & Asset
availability optimise generation
3
4
Total
x
=
Access to and price of fuel* drives
financials & risk position
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 $9.5GJ, carbon price of $70/unit and thermal portfolio heat rate (9.5GJ/MWh)
5.Length of 194GWh for 1H24 assumed
6.Locational losses of 4.3% on spot purchases and settlement
of CFDs sold at a wholesale price of $139/MWh
10
12
12
20
4
9
8
312
325
1
Normalised and expected EBITDAF assumptions
1H24 results
With reconciliation to actual performance
x
Lower market channel price
Normalised & Expected
Lower renewables
Other income
Actual
Renewable generation below mean (-86GWh)
at expected thermal SRMC
Fixed costs
Received ‘loss and constraint excess’ (LCE) rebates.
Prioritisation of geothermal activity and resource
Expected losses from distressed gas
sales not realised
Increased long–term channel price
Retail net price of $150/MWh in 1H higher than full year
expectation
C&I net price of $135/MWh in 1H lower than full year
expectation
Gas, carbon, acquired generation price
Gas & carbon price as well as thermal efficiency were favourable
Lower than expected sales volumes, largely offset by reduced
SRMC of thermal generation
Net volume impact
One-off write-offs
Impact of one-off write offs for Peaker damage (-$4.0m) &
CRM system project not continuing as originally planned (-$3.9m)
=
33
Contact generation output sold to the national grid (GWh)
Generation and sales position
1,726
1,652
1,649
1,524
1,659
1,605
1,652
1,635
2,045
1,886
1,984
2,391
2,053
1,916
966
836
825
870
360
817
1H181H191H201H211H22
246
1H231H24
Thermal
generation
Hydro
generation
Geothermal
generation
4,327
4,533
4,359
4,378
4,411
3,905
4,385
Operational data
Renewable % of
own generation
sold to grid
82%81%
80%
78%
92%
94%81%
Geothermal generation (GWh)
Te Huka
Ōhaaki
Poihipi
Wairākei
Te Mihi
Geothermal generation was up 47GWh (3%) on 1H23, ~34GWh (73%) of the uplift is attributable to
the increased consented mass take from the Wairākei steam field (from 245,000 to 250,000 t/d).
719
716
709
559
692
690
715
539
486
493
567
531
489
518
209
203
181
129
168
154
161
161
155
171
165
170
165
159
104
107
99
1H18
92
1H19
95
1H201H21
99
1H221H23
99
1H24
1,726
1,652
1,649
1,524
1,659
1,605
1,652
Hydro generation (GWh)
An uncharacteristic El Niño weather pattern resulted in 1H24 hydro volumes being down 137GWh (-7%) on
1H23 as inflows for the period were the lowest seen in five years.
415
244
375
339
1,509
1,872
2,178
2,013
2,123
2,674
1,855
-35
-73
-707
-107
-960
-181
161
1H18
246
1H191H20
-274
1H211H221H23
242
1H24
1,635
2,045
1,886
1,984
2,391
2,053
1,916
Inflows stored include uncontrolled storage lakes
Inflows
Inflows
stored
Spill
Thermal generation (GWh)
463
649
593
620
168
161
646
369
69
119
130
87
171
133
114
111
117
104
67
2
50
1H18
4
51
1H19
1
50
1H20
3
48
1H21
2
47
1H22
2
45
17
1H23
0
00
1H24
1,016
887
875
918
407
291
817
Te Rapa
Spot
Whirinaki
Te Rapa
Direct
Peakers
TCC
1H24 thermal generation volumes were 526GWh (181%) higher than 1H23 due to three factors:
additional thermal generation was required to meet the increased sales position in response to the
Tauhara delay; additional gas was available due to the Methanex outage; and closure of Te Rapa
increased thermal efficiency as more gas was able to be run through TCC.
34
Plant and fuel performance
Geothermal fuel extracted at Wairākei vs consented (mT)
Wairākei, Poihipi and Te Mihi conversion effectiveness
(MWh per kT extracted)
% of geothermal fluid extractedWairakei mass extracted
10
20
30
40
50
0
101%
1H18
97%
1H19
100%
1H20
95%
1H21
100%
1H221H23
100%
1H24
46
43
46
44
43
45
45
96%
+10%
31.0
32.3
30.7
30.3
31.4
29.8
30.3
1H181H191H201H211H221H231H24
+2%
Geothermal fuel performance
Taranaki combined cycle (TCC)
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
1H2037778%36%59311367
1H2137796%37%62012779
1H22377100%10%16818331
1H2337789%10%16110717
1H2437769%39%64612782
Hydro
Geothermal
Stratford Peakers
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
1H2078494%54%1,88698184
1H2178485%57%1,984110218
1H2278483%69%2,39190215
1H2378487%59%2,05352107
1H2478493%55%1,916123235
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
1H2042594%88%1,649106175
1H2142586%81%1,524118180
1H22410
1
96%92%1,659105175
1H2341094%89%1,6055689
1H24
41095%91%1,652134221
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
1H20
202
63%13%119
15218
1H21
202
86%14%130
15120
1H22
202
74%10%87
21619
1H23
202
57%2%17
1903
1H24
202
56%19%171
15226
Plant availability
Availability Factor calculation includes all station outages (Planned, Maintenance, Forced) but does not consider plant deratings.
1
Reduction in geothermal net capacity is a result of decommissioning of wells on the Wairākei steam field.
Net
capacity
(MW)
Availability
(%)
Capacity
factor
(%)
Electricity
output
(GWh)
Pool revenue
($/MWh)($m)
1H20
158
97%0%12690.4
1H21
158
91%0%33050.8
1H22
158
98%0%27831.8
1H23
158
97%0%22740.4
1H24
158
100%0%000.0
Whirinaki
In October 2022 new consents were granted increasing the total allowed
geothermal mass take by 2% (from 245,000 to 250,000 t/d), providing an
additional ~50GWh of geothermal generation per annum.
35
Hawea storage (GWh)
Gas storage (PJ)
Closing storage
Closing storage (current)
Fuel storage movements
Source: NZX hydro
226
97
175
166
259
116
253
191
248
300
230
324
189
324
264
242
-377
-222
-239
-231
-333
-187
-325
-293
2H201H212H211H222H221H232H231H24
Inflows
Opening storage
Releases
97
175
166
259
116
253
191
141
4.5
5.0
6.1
5.0
5.8
7.8
4.7
2.7
3.7
1.5
2.2
0.8
1.7
2.4
0.5
2.7
1.7
0.9
-1.0
-1.1
-1.9
-0.9
-3.5
-0.7-0.7
-1.5
-4.0
1H202H201H212H21
-0.4
1H222H221H232H231H24
Gas Injected
Gas Extracted
Opening Storage
5.0
6.1
5.0
5.8
7.8
4.7
2.7
3.7
3.1
Operational data
Following the completion of a joint technical working group, set up by Contact and the Ahuroa Gas Storage Facility (AGS) owner FlexGas in 2022,
Contact advised the market in December 2022 that approximately 4PJs of gas owned by Contact and currently stored in AGS may only be
available for extraction at the end of the contract in 2033. Excluding this volume, the estimated storage capacity of the facility is ~6-8PJ (P-50).
Information about the total volume of gas in the facility can be found at https://www.gasindustry.co.nz/data/gas-storage/
0
Long-term storage
balance (PJ)
0
0
0
0
0
4
4
4
Long-term storage transfer
36
Contracted gas volumes (PJ)
Uses of gas (PJ)
Gas storage monthly injections and extractions (PJ)
Contracted and stored gas
Gas injectedGas extracted
7.6
8.1
3.4
0.9
2.3
6.3
7.0
4.5
4.5
6.1
1.7
5.5
4.5
2.0
5.3
7.4
5.9
2.3
5.5
5.2
CY19CY20
-0.2
CY21CY22
0.2
CY23CY24
1
CY25
2
16.6
16.9
14.6
15.5
13.6
11.7
-0.1
7.0
0.26
-0.24
Jan-
23
0.21
-0.09
Feb-
23
0.24
-0.30
Mar-
23
0.55
-0.01
Apr-
23
0.25
-0.04
May-
23
0.20
-0.03
0.12
-0.28
Jul-
23
0.03
Jun-
23
-0.61
Aug-
23
0.25
-0.28
Sep-
23
0.28
-0.16
Oct-
23
0.14
-0.06
Nov-
23
0.11
-0.14
Dec-
23
8.1
9.4
9.3
9.8
6.6
9.8
6.3
8.8
-1.1
1.1
-0.7
-2.0
3.1
-2.0
-1.0
0.6
-5.3
-8.2
-6.7
-4.4
-6.5
-3.3
-2.7
-6.7
-1.4
-1.7
-1.4
-1.6
-1.3
-1.6
-1.1
-1.4
-0.6
-1.6
-1.9
-2.7
-1.4
-1.3
-0.2
2H20
-0.5
1H212H211H222H221H232H231H24
Net extraction
(injection)
Generation
Customer sales
Wholesale sales
Purchases
Short-term gas
Genesis
Swap
Maui
Pohokura
Operational data
1
Maui and Pohokura volumes for CY24 reflect forecast volumes.
2
No forecast currently available for CY25. Contracted amounts shown.
37
Contractual fuel position sufficient to
support expected sales position
Fuel position
Portfolio requirements for thermal generation FY24 (TWh)
Gas supply and demand FY24 (PJ)
Excludes stored gas
10.7PJ**
Hydro variation >>
•Hydro generation in FY12.
** Assumes mix of TCC and peaker generation (portfolio heat rate (8.2GJ/MWh)).
1
Gas used in generation and retail gas sales.
GeothermalExpected
FY24
generation
from
onstream
assets
(including
losses)
Hydro in
"extreme
dry" year*
Maximum
thermal
required
"Extreme
dry" to
"mean"
year swing
Mean
thermal
required
Maximum
thermal
required
"Mean" to
"wet" year
swing
Minimum
thermal
required
10.7
5.8
2.5
8.1
Mean Year
demand
FY24 Position
13.2
13.9
9.0
2.2
1.3
0.9
-3.3
-2.9
-0.5
-1.0
-0.3
Options in a dry year:
•Access to stored water
in Hawea
•Stored gas
•Purchase spot gas
•Acquire generation from
ASX
•Contracted gas above
expected mean position
Options in a wet year:
•Gas swaps
•Gas sales
•Hawea storage
•Sell short term ASX
Acquired
generation
(actual and
contracted)
Gas used in 1H24
1
Contracted gas
remaining for FY24
Mean Thermal
Retail
38
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 2023
(1H24)
6 months ended
31 December 2022
(1H23)
Variance onprior
year
$m%
Underlying
1
ReportedUnderlying
Reported
2
Against underlying
Profit
134153
79
(7)
5570%
Depreciation and
amortisation
126111(15)(14%)
Change in fair valueof
financial instruments
-517(22)(129%)
Net interest expense172019211%
Tax expense536032(2)(21)(66%)
EBITDAF
325354
2571376826%
Depreciation and amortisation, 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 1H23 are as follows:
•Depreciation and amortisation: increased by $15m and
is linked to re assessments in useful life of thermal plant
and Wairākei in light of expected final investment decision
on replacement. This was partially offset by extending the
useful life of SAP assets upgraded as part of recent S/4
Hana upgrade.
•Net interest expense: Lower than 1H23 with higher
capitalised interest on Tauhara and Te Huka projects
partially offset by higher interest on average borrowings.
•Tax expense for the period increasing by $21m following
higher operating earnings.
Non-GAAP profit measure
1
Contact has recognised a net onerous contract provision release for AGS of $29m within EBITDAF and $19m within profit after tax and interest. Underlying performance excludes these impacts. All variances and commentary reflect movements in
underlying performance.
2
Contact has made reclassifications to better align with IFRIC guidance on IFRS 9 resulting in realised gains/losses from market derivatives not in a hedge relationship (includes market making activity) no longer being reported in operating income
(EBITDAF). 1H23 figures restated accordingly.
39
Historical financial information
Unit1H201H211H22
1H23
1
1H24
Underlying
2
ReportedUnderlying
2
Reported
Revenue$m1,1101,1411,1419941,306
Expenses
3
$m889895819737857981952
EBITDAF$m221246322257137325354
Profit$m597813479(7)134153
Operating free cash flow$m12015713171187
Operating free cash flow per sharecps16.821.916.89.123.7
Dividends declared cps16.014.014.014.014.0
Total assets$m4,8504,7384,9785,4086,059
Total liabilities$m2,1702,2122,0272,7483,375
Total equity$m2,6802,5262,9512,6602,684
Gearing ratio
4
%29.931.119.330.638.4
Historic performance
1
Contact has made reclassifications to better align with IFRIC guidance on IFRS 9 resulting in realised gains/losses from market derivatives not in a hedge relationship (includes market making activity)
no longer being reported in operating income (EBITDAF). 1H23 Expenses, EBITDAF and operating free cash flow are restated accordingly.
2
Contact has recognised a net onerous contract provision release for AGS of $29m within EBITDAF and $19m within profit after tax and interest. Underlying performance excludes these impacts.
3
Includes realised gains/(losses) on risk management derivatives not in a hedge relationship.
4
Gearing ratio is calculated as: (Senior debt - including finance lease liabilities) / (Senior debt - including finance lease liabilities + Equity).
40
1H241H23
Six months ended 31 December 2023Six months ended 31 December 2022
VolumeGWAPVolumeGWAP
Note: this table has not been rounded andmight not addGWh$/MWh$mGWh$/MWh$m
2
Electricity sales to Retail segment1,989 141 280 1,988 121 241
Electricity sales to C&I (netback)686 118 81 781 112 88
Electricity sales –Direct to Customer--(0)45 165 7
Electricity sales to C&I686 118 81 826 115 95
CfDs–Tiwai support sales458 486
CfDs-Long term sales390 210
CfDsand ASX -Short term sales879 361
Electricity sales –CFDs1,727 112 193 1,057 74 78
Total contracted electricity sales4,402 126 554 3,872 107 414
Steam sales118 16 2 336 55 19
Other income2(4)
Net income on gas sales2 1
Net income on electricity related services03
Net other income40
Total contracted revenue4,520 124 559 4,208 103 433
Generation costs
1
4,386 (40)(175)3,950 (31)(122)
Acquired generation cost239 (127)(30)131 (123)(16)
Generation costs (including acquired generation)4,624 (44)(205)4,081 (34)(138)
Spot electricity revenue4,386 132 579 3,905 58 225
Settlement on acquired generation239 130 31 131 63 8
Spot revenue and settlement on acquired generation (GWAP)4,624 132 610 4,036 58 233
Spot electricity cost(2,675)(142)(380)(2,770)(70)(193)
Settlement on CFDs sold(1,727)(133)(230)(1,057)(54)(57)
Spot purchases and settlement on CFDs sold (LWAP)(4,402)(139)(610)(3,827)(65)(250)
Trading, merchant revenue and losses 223 (0)210 (17)
Wholesale EBITDAF underlying
1
354279
Onerous contract provision29
1
(120)
Wholesale EBITDAF reported383159
Wholesale segment
Segmental performance
1
Contact has recognised a net onerous contract provision release for AGS of $29m within EBITDAF and $19m within profit after tax and interest. Underlying performance excludes these impacts.
2
Contact has made reclassifications to better align with IFRIC guidance on IFRS 9 resulting in realised gains/losses from market derivatives not in a hedge relationship (includes market making activity) no longer being
reported in operating income (EBITDAF). 1H23 figures restated accordingly.
41
Residential electricityunit
1H211H221H231H24
Residential gasunit
1H211H221H231H24
Average connections#357,756367,199
381,222
386,540
Average connections#60,56363,18266,796
67,658
Sales volumesGWh1,3491,408
1,445
1,478
Sales volumesTJ954970881
916
Average usageMWh per ICP3.83.83.8
3.8
Average usageGJ per ICP15.715.413.2
13.5
Tariff$/MWh251.1251.5261.4
281.2
Tariff$/GJ31.332.638.1
41.3
Network, meters and levies$/MWh-116.2-115.9-118.2
-122.1
Network, meters and levies$/GJ-15.3-16.2-20.7
-20.8
Energy costs$/MWh-101.1-110.8-128.7
-149.9
Energy costs$/GJ-8.3-11.3-10.2
-9.7
Gross margin$/MWh33.824.814.5
9.2
Carbon costs$/GJ-1.4-1.9-4.2
-3.0
Gross margin$ per ICP1279555
35
Gross margin$/GJ6.33.23.0
7.8
Gross margin$m453521
14
Gross margin$ per ICP995039
106
Gross margin$m633
7
SME electricityunit
1H211H221H231H24
SME gasunit
1H211H221H231H24
Average connections#51,40748,32347,70244,746Average connections#3,8583,9183,6563,100
Sales volumesGWh465392421392Sales volumesTJ720628635465
Average usageMWh per ICP9.08.18.88.8Average usageGJ per ICP186.7160.4173.6149.9
Tariff$/MWh230.7239.0249.2276.6Tariff$/GJ15.818.623.129.5
Network, meters and levies$/MWh-104.4-113.0-113.0-114Network, meters and levies$/GJ-7.9-8.7-8.4-11.4
Energy costs$/MWh-99.7-109.0-129.8-148.0Energy costs$/GJ-8.3-11.3-10.2-9.7
Gross margin$/MWh26.517.06.414.6Carbon costs$/GJ-1.4-2.0-4.2-3.0
Gross margin$ per ICP24013856128Gross margin$/GJ-1.8-3.30.35.5
Gross margin$m12735Gross margin$ per ICP-474-53254828
Gross margin$m-2-30.23
Broadband
unit
1H211H221H231H24
Retail segment EBITDAF
1H211H221H231H24
Average connections#33,19757,49874,97488,594Electricity Gross margin$m58412419
Tariff$/cust/mth65.271.870.473.2Gas Gross Margin$m51310
Network, provisioning, modems$/cust/mth-74.0-61.6-62.8-64.4Broadband Gross Margin$m-2445
Gross margin$/cust/mth-8.810.27.68.8Total Gross Margin$m61463134
Gross margin$m-2445Other income$m3353
Other direct costs$m-1
Other operating costs$m-33-33-35-37
Retail segment EBITDAF$m30161-1
Corporate allocation (50%)$m-7-5-11-14
Retail EBITDAF$m2311-10-15
EBITDAF margins (% of revenue)%4.60%2.10%-1.80%-2.43%
Retail segment
Historic performance
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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