Slides
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11 2025 full year results presentation 18 August 2025 Twelve months ended 30 June 2025
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2 Disclaimer and important information This presentation contains summary information and statements about Contact and its businesses and activities as at the date of this presentation. The information is not held out as being complete or exhaustive, nor does it contain all the information which a prospective investor may require in evaluating a possible investment in Contact. 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. Subsequent to balance date, Contact acquired Manawa Energy Limited (Manawa) on 11 July 2025 via a scheme of arrangement. Manawa was delisted from the NZX on 5 August 2025, following early bond redemption. Contact recommends that you read this presentation in conjunction with both its market announcements and those of Manawa Energy Limited and the materials attached to those announcements, and in particular the market announcements and materials Contact released on the date of this presentation. These are available on the NZX website (at www.nzx.com), for Contact only the ASX website (at www.asx.com.au) and on Contact's or Manawa's website www.contact.co.nz or https://www.manawaenergy.co.nz/investor-centre. 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, operating free cash flow and return on invested capital 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 legal, financial, tax, accounting, investment or other advice. Further, this presentation does not constitute a recommendation or offer of financial products for subscription, purchase or sale, or an invitation or solicitation for such offers, and may not be relied on in connection with any purchase of a Contact security. Any person who is considering an investment in Contact should obtain independent professional advice prior to making an investment decision, and should make their investment decision having regard to their own objectives, financial situation, circumstances and needs. 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. All trademarks, service marks and company names are the property of their 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.
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3 FY25 highlights / Mike Fuge, CEO Market update / Mike Fuge, CEO Financial results and outlook / Matt Forbes, CFO 2 3 1 Agenda 33 Update on Manawa and strategic delivery / Mike Fuge, CEO 34 Supporting materials 3335 4 - 8 9 - 15 16 - 29 30 - 39 40 - 55
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4 Fonterra electrification Contact to supply 540GWh p.a. at Whareroa by 2028 (~75% new demand) Greymouth and OMV gas contracts Secured up to 10PJ p.a. to CY2032 140,000 households choosing discounted or free off-peak energy FY25 highlights Added to the MSCI Global Standard Index +17% +13% Continued representation within Dow Jones Sustainability Index Delivering for shareholders NPAT (underlying) $261m up $31m YoY EBITDAF (underlying) $774m up $111m YoY Dividend CPS 39c up 2c YoY +5% Stations online $1.1b of projects under constructionTransaction completed 11th July 2025 Integration underway Secured access to ~6PJ Methanex gas, supporting the market in dry sequences Medium-term gas supply supporting generation needs & gas-reliant businesses Taranaki Combined Cycle gas plant made available for winter 2025 Tauhara 174MW 1.45TWh Te Huka 3 51MW 0.43TWh Delivering transformative portfolio change Delivering renewable energy growth Delivering financial performance Delivering for customers Delivering for the market Glenbrook-Ohurua | 100MW BESS Te Mihi Stage 2 | 101MW Geothermal Kōwhai Park |168MWp Solar
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5 Refreshed leadership, delivering growth Leadership team refreshed to match the scale, complexity and ambition of the business Mike Fuge Chief Executive Officer • Jack Ariel, Major Projects Director, retired. • Matt Forbes appointed Chief Financial Officer. • Carolyn Luey appointed Chief Retail Officer. Jan Bibby Chief People Experience Officer Chris Abbott Chief Corporate Affairs Officer John Clark Chief Generation Officer Tighe Wall Chief Technology Officer Matt Bolton Manawa Integration Director Dorian Devers Chief Renewable Growth Officer Changes (During 2H FY25) Matt Forbes Chief Financial Officer Carolyn Luey Chief Retail Officer
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6 1 In FY25, the release of the AGS onerous contract provision increased reported EBITDAF by $98m and profit by $71m. In FY24 the net movement in this provision added $12m to EBITDAF and $5m to profit. This is the only adjustment from reported to underlying performance. All variances and commentary reflect year-on-year changes in underlying performance. 2 Refer to slide 50 for a definition and reconciliation of Profit to EBITDAF. Summary of key financial performance measures Building for the future, ready for today Performance powered by geothermal expansion and resilient risk management FY25 was shaped by challenging market dynamics: • Two historically significant dry periods reduced hydro output and increased reliance on thermal generation. • Gas production fell 20% year-on-year, deepening fuel scarcity. • Spot and short-term futures prices spiked, then eased as inflows recovered and Methanex gas was secured. • Lines charges rose ~20% from April 2025, adding further cost pressure. Contact’s diversified portfolio and proactive risk management supported strong performance in a volatile year: • Geothermal output rose 34%, with Tauhara and Te Huka 3 delivering 1.5TWh of reliable baseload energy. • TCC was retained to support winter 2025, despite being scheduled for closure. ‒ Combined with AGS storage, this enabled Contact to secure Methanex gas and supply renewable-only generators during dry periods—helping stabilise the market. Market FY25 highlighted several medium-term challenges: • Ongoing gas scarcity with limited options to increase gas supply. • Rising costs for long-term risk management products. • Growing seasonal price spreads, especially between summer and winter. • Increased price volatility as more intermittent generation enters the market. Medium term Contact is well-positioned for medium-term market conditions: • Renewable build-out progressing across solar, geothermal and battery projects. • Manawa acquisition adds portfolio flexibility and favourable market channel exposure. • Long-term gas contracts to 2032 support intermittent generation and key customers. • Strategic customer partnerships support decarbonisation. 3 ROIC is four-year average. See slide 25 for the operating free cash flow reconciliation and for the basis of calculation of return on invested capital. For FY24, $46m of growth capex has been reclassified to stay-in business capex, ensuring that spend is classified according to which assets receive the most benefits under a revised scope of Te Mihi Stage 2. 4 Relates to interim and final FY25 dividends declared. 5 Includes capitalised interest. Twelve months ended 30 June 2025 (FY25) Twelve months ended 30 June 2024 (FY24) Underlying1 Reported Against underlying1 EBITDAF2 $774m $872m ↑ 17% from $663m Profit $261m $331m ↑ 13% from $230m Profit per share 32.7 c 41.6 c ↑ 12% from 29.1 c Operating free cash flow3 $434m ↑ 2% from $424m Operating free cash flow per share3 54.4 c ↑ 1% from 53.9 c Average ROIC3 4.9% ↑ From 3.7% Dividend declared4 $355m ↑ 22% from $292m Dividend declared per share4 39.0 c ↑ 5% from 37.0 c Stay-in-business (SIB) capital expenditure (cash) $110m ↓ 29% from $156m Growth capital expenditure (cash)5 $363m ↓ 14% from $424m FY25
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7 Delivering on the plan FY25 operational plan Grow renewable development Decarbonise our portfolio Create outstanding customer experiences Strategic theme Grow Demand Impressive delivery of the FY25 strategic targets outlined at the start of the year FY25 achieved ▪ New demand facilitated since FY21 to reach >120MW. ▪ Achieve FID for CO2. ▪ Add 15MW of flexible demand. ▪ Achieve FID for Te Mihi Stage 2. ▪ Lodge consent for Stratford solar. ▪ Achieve consent on Glorit solar. ▪ Achieve consent on Southland Wind. ▪ Te Huka 3 online Q4 CY2024. ▪ Glenbrook-Ohurua BESS1 on-track for online Q1 CY2026. ▪ Kōwhai Park solar on track for online for Q2 CY2026. ▪ Additional investment in carbon offsets. ▪ Close TCC2 gas generation plant. Expected to close December 2024. ▪ Sustained entry into the DJSI. ▪ Electricity net price up by 2-3%. ▪ Multi-product customers >149k (up from 140k). ▪ Target cost to serve <$123/connection.3 ▪ Scale Hot Water Sorter programme to >20k homes (up from ~5k). Complete / on-track Minor delay and / or cost increase Major delay and / or cost increase Key: New demand facilitated and contracted since FY21 ~230MW (88MW online) up from 105MW. 15MW of additional flexible demand contracted, taking total contracted volume to 188MW (141MW online). CO2 Final Investment Decision (FID) now targeted for FY26. Glenbrook-Ohurua BESS under construction. Expected online in Q1 CY2026. Achieved FID on Te Mihi Stage 2 geothermal station. Expected online in Q3 CY2027. Consenting process underway for Glorit solar. Earliest expected FID FY26. Consent declined under COVID-19 Fast Track. Contact has been accepted under the new Fast Track Approvals Act and expects to lodge a substantive application shortly. TCC made available for Winter 2025 to support security of supply. Closing 2025. Up >3%; full recovery of lines cost increases; partial recovery of rising wholesale costs. More than 149k multi-product customers, up ~7%. Cost to serve $116 / connection. Reached >20k homes in the programme and shifted 4GWh residential demand off-peak in FY25. Sustained inclusion in DJSI Asia-Pacific (one of only five New Zealand companies). Purchased additional ~8% interest in Forest Partners (taking total to 22%). Te Huka 3 online December 2024 at 54MW operating capacity. Final commissioning completed June 2025. Kōwhai Park solar under construction. Expected online in Q2 CY2026. Consent lodged for Stratford solar. 1 Battery Energy Storage System. 2 Taranaki Combined Cycle. 3 Includes customer acquisition costs. Strategy delivery
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8 Renewable projects under construction Target schedule Online in Q1 CY2026 1 Battery Energy Storage System. 2 Includes sunk cost of $66m and $5.4m for Te Mihi Stage 2 and Glenbrook-Ohurua BESS respectively. Excludes capitalised interest. 3 Excludes financing costs of $43m. Includes development costs. Key facts & progress updates Contact is currently leading the build of ~$1.1bn in renewable infrastructure across New Zealand Battery capacity / storage 100MW / ~200MWh Up to $163m2 Total project costs Te Mihi Stage 2 geothermal Glenbrook-Ohurua BESS1 Kōwhai Park solar farm4 ▪ All 28 transformers and 56 Megapacks are now installed on site. ▪ Electrical connections between Megapacks and transformers are well advanced. ▪ Balance of plant works—including switch and control rooms, cabling, and auxiliary transformers—are progressing well. ▪ Concrete foundations for key infrastructure are largely complete. Progress update Target schedule Online in Q3 CY2027 Net capacity / annual generation 101MW / 0.8TWh $712m2Total project costs ▪ Earthworks are nearing completion. ▪ The power station site has been handed over to the EPC contractor, with foundation trenching and excavation now underway. ▪ Wairakei extension works have commenced, including planning for major upgrades to electrical reticulation systems. Progress update ▪ Construction village and earthworks are well advanced. ▪ Most PV modules, trackers, and inverters are now on site. ▪ The first row of solar panels—the “golden row”—has been successfully installed. Progress update Target schedule Online in Q2 CY2026 Net capacity / annual generation 168MWp / 0.3TWh $273m3Total project costs 4 The Kōwhai Park solar farm is part of Contact’s 50/50 JV with Lightsource bp. Strategy delivery
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9 Market update
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10 National electricity demand Source: EMI, Contact. Does not include NZAS. National electricity demand (TWh)Regional change (%) FY25 vs FY24 Source: EMI, Contact. NZAS demand response is estimated by comparing total demand in FY25 against average demand at the Tiwai node over the preceding 4 years. Market demand NZ electricity demand down ~1% even when normalised for NZAS demand response National electricity demand in FY25 reflected the impact of extreme weather and challenging conditions. Overall demand was down ~3% year-on-year, driven by dry conditions and demand reductions from customers exposed to fuel scarcity though high prices. Adjusting for NZAS demand response—called by Meridian to support lower hydro conditions— underlying demand fell ~1%. Notable regional changes included: • A 58% drop in demand at the central North Island node following the closure of the Winstone Karioi pulp mill and Tangiwai sawmill in August 2024, reflecting broader challenges in wood and paper processing without the protection of fixed price electricity hedging. • A 12% decline in South Canterbury, concentrated in irrigation nodes, driven by high inflows between September and December 2024. • A 16% increase on the East Coast, as Pan Pac’s Whirinaki plant—closed after Cyclone Gabrielle in 2023—gradually resumed operations through 2H24 and 1H25. (3%) (4%) 1% (12%) (6%) (3%)(1%) (2%) 9% 0% (3%) (1%) (58%) (1%) (0%) 1% (0%) 2% 16% 5.1 4.9 5.0 5.0 5.0 4.2 10.3 10.6 10.2 10.5 11.2 10.9 25.8 26.1 25.8 25.6 25.9 25.7 FY20 FY21 FY22 FY23 FY24 0.8 FY25 41.2 41.6 41.1 41.1 42.1 41.6 +1% -1% NZAS demand response North Island South Island (ex NZAS) NZAS 40.9 -3%
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11 Near term demand outlook is positive Committed new load and consistent residential progression accounts for more than half of market growth expectations in the next 5 years 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 0 41 42 43 44 45 46 47 48 Calander year NZ Electricity Demand (TWh/year) +0.3% CAGR2 Estimates of future demand by sector3 National demand growth over time1 Future demand sources committed growth Residential decarbonisation & EV uptakeAdditional / faster industrial electrification Data centres Additional and / or faster industrial decarbonisation resulting from higher cost and less available natural gas 1.3% CAGR2 Faster EV uptake and residential decarbonisation (heating / cooling) Data centre build out consistent with current pipelines / projections 1.1 0.9 1.2 2024 actual Dairy 0.2 Metals Data centres Residential 2030 identified Future projects 46.2 2030 EDGs 44.9 3.3 41.6 +8.0% total identified growth Residential Dairy Metals Data centres Actual demand data (EMI) Contracted / under construction demand MBIE EDGs 2024 – Reference scenario Market demand +1.3 TWh Known & committed Market interest 1.7% CAGR2 1 MBIE EDGs reference case used as a proxy for market expectations given its use by Transpower for capital investment planning. 2 Compound annual growth rate. 3 Forecast does not include assumptions around potential industrial demand loss or line losses.
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12 Supply Commentary – Generation Mix FY25 • Hydro generation was down ~10% on FY24, 9% below the post- market mean and the lowest annual volume since 2008. This reflected two historically dry periods, including record-low inflows between January and March 2025. • Gas generation increased to support the market, enabled by short-term gas from Methanex, which paused methanol production to make supply available. • Geothermal rose with Tauhara and Te Huka 3 contributing 1.5TWh— geothermal delivers twice what wind does. • Solar increased from 10GWh to 100GWh, ~0.2% of total market generation. • FY25 highlighted the importance of flexible, dispatchable generation and strategic fuel reserves in managing volatility and supporting the transition to renewables. Generation by type (TWh) Hydro Storage – FY25 Summary Hydro storage was highly volatile across the year: • The financial year began with storage well below average due to low inflows in late FY24. • Heavy rainfall in August lifted storage to a peak in December. • From January to March, total inflows (across Taupo, Waitaki, Clutha and Te Anau) were the lowest in 99 years. • With gas supply tight, the market conserved hydro storage ahead of winter 2025. 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 Jul- 23 Dec- 23 Jul- 24 Dec- 24 Jun- 25 1H24 1H25 Storage TWh National hydro storage Carbon emissions (mT) Source: EMI (generation data), MBIE (emissions data) and NZX Hydro data. 1 Carbon emissions for FY25 Apr-Jun quarter has been estimated using historic conversion rates with actual generation data. Two historically significant dry periods Fuel supply Lower hydro output offset by new geothermal production and lower demand 2H252H24 3.1 2.9 2.7 2.5 7.1 3.5 3.7 27.0 7.6 9.0 23.9 21.4 3.1 2.4 1.7 3.9 4.20.5 FY23 FY24 FY25 Gas Coal Hydro Geothermal Wind Solar Other nonidentified generation 43.1 44.1 42.9 4.1 1 2.3 4.2 1 2 1. Winter 2024 2. Summer 2025 Mean Actual
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13 Net domestic gas production Volatile pricing driven by hydro and gas availability Wholesale and futures electricity pricing ($/MWh) Wholesale market 0 50 100 150 200 250 300 350 400 450 500 Jun- 16 Jun- 17 Jun- 18 Jun- 19 Jun- 20 Jun- 21 Jun- 22 Jun- 23 Jun- 24 Jun- 25 10 year average spot price $126 Long-dated futures (>12 months) Short-dated futures (<12 months) Monthly average spot price Source: EMI wholesale pricing Pricing Commentary – FY25 • Spot and short-term futures prices spiked during two dry periods—Winter 2024 and Summer 2025—driven by low hydro inflows, limited wind, and a 20% year on year reduction in gas supply. Prices eased as hydro inflows recovered and Methanex gas was made available for generation. • Long-dated futures rose in response to declining domestic gas forecasts (down by 20% on average) and the rising cost of firming intermittent renewables. While the HFO agreement (including a strategic reserve at Huntly) helps reduce scarcity risk, prices continue to reflect the cost of dispatchable fuel—whether gas, coal, or demand response—needed to meet winter demand. 0 2 4 6 8 10 12 14 May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr 2024 2025PJ 1 2 Source: MBIE gas statistics; 2P reserves data. 0 50 100 150 2025 2026 2027 2028 2029 2030 2024 forecast 2025 forecast Average annual forecast production (2025 – 2030) Average monthly gas production down 20% year-on-year Latest annual production forecasts stepped down 24% on average Current gas deliverability forecasts point to continued steep decline
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14 Retail Electricity Market Connection Trends • Competition remains strong, with churn steady at ~19% despite elevated wholesale prices. • Tier 1 retailers now hold ~85% market share. Growth over the last 2 years was led by Meridian (+12% over two years, excluding Flick), followed by Genesis (+4%) and Contact (+5%). Mercury remained stable. • Meridian’s acquisition of Flick Energy (announced May 2025) adds ~41k connections, though these are not yet reflected in reported market share. • Tier 2 retailers are losing ground, with most stepping back from customer acquisition. Flick (+27%) and 2Degrees (+9%) were exceptions. • Contact added 20k residential connections over the past two years, reaching 20% market share. Change in retail customer electricity connections (000s) 30 June 2023 – 30 June 2025 2yr % change2yr ICP delta (1000s) Retail electricity tariff changes (c/ kWh) Tier 2: -9k connections Retail Pricing Trends • Residential electricity prices have risen steadily, with a compound annual growth rate of ~4% over the past five years to March 2025. The average increase in the year to March 2025 was ~4%. • Cost pressures are expected to continue. Key drivers include: ‒ Higher wholesale electricity prices, particularly in winter when usage is highest. ‒ Increased cost of transmission and distribution infrastructure.2 These factors are expected to keep upward pressure on retail prices over the near term. Continued investment in new renewable generation is expected to bring down electricity costs over time. 12 months ended: Tier 1: +66k connections Source: EMI – residential ICPs only Source: MBIE 18.2 18.6 19.5 20.7 20.9 11.1 11.6 12.0 12.4 13.5 Mar-21 Mar-22 Mar-23 Mar-24 Mar-25 29.4 30.2 31.5 33.1 34.4 +4% Retail strategic value outweighs margin headwinds Retail electricity market Medium-term cost pressures not deterring long-term positioning or competition Lines (c/kWh) Energy & Other (c/kWh) 1 1 Compound annual growth rate. 4% 5% 0% 12% -3% -6% 27% 9% 8% -20 0 10 20 30 -30 Genesis Contact Mercury Meridian Nova Pulse Flick -21% Electric Kiwi 2Degrees/ Vocus Other 2 From 1 April 2025, Commerce Commission-approved changes to network charges began to take effect, increasing household bills by $10–$25 per month on average (depending on region and usage profile).
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15 Responding to the energy challenges that matter Investing at pace Making the most of favourable consenting environment Fuel security and dry year risk Regional growth Energy wellbeing ▪ Generation totalling 6.7TWh built or committed by industry between 2020 and 2027. ▪ 335MW of grid-scale batteries now online or under construction in New Zealand. ▪ Industry-wide focus on energy wellbeing and reducing punitive practices. ▪ Disconnections now viewed as last resort. Contact is investing in renewables, flexible storage, and demand response - guided by clear market signals and long-term national priorities; These actions reflect strong alignment with government objectives and reinforce the value of stable, predictable policy settings 1 Based on observed volume at the Tiwai node. 2 HFO agreement is subject to Commerce Commission review. Leading sustainable decarbonisation in the transition to Net Zero 2050 We are anticipating the government’s response to the review of electricity market performance in September We expect this to propose sensible market enhancements to improve outcomes for consumers ▪ Removed all disconnection and reconnection fees and financial barriers for reconnection. ▪ Free power and broadband to all Women’s Refuge safehouses and refuges nationwide along with other targeted social agencies. ▪ 225MW of baseload renewables brought online at Tauhara and Te Huka 3 geothermal stations in CY 2024. ▪ Investments in battery and solar to come online in CY 2026. Te Mihi Stage 2 to come online CY 2027. ▪ Fast Track Approvals Act passed into law. ▪ Changes to national policy statements proposed. ▪ Replacement Resource Management legislation to be introduced before end of year. ▪ Contact and Manawa together can move at pace on a robust pipeline of consentable developments and reconsents. ▪ Engaging on RMA reforms, including seeking automatic reconsent for schemes <50MW. ▪ Entered 50MW HFO agreement.2 ▪ Secured up to 10PJ p.a. gas supply to CY 2032 with option to extend. ▪ Improved performance of AGS gas storage enhances flexibility. ▪ NZAS demand response activated, releasing ~0.8TWh to the market in FY25.1 ▪ Signed 10 year, 150MW HFO agreement keeping rankines available for dry year risk.2 ▪ Methanex short-term gas interruptibility achieved. ▪ Major renewable developments underway creating jobs in the regions. Including Southland, Central North Island, Hawkes Bay, Northland and wider. • Contact’s geothermal development programme has led to job creation in Taupo region. • Tauhara alone involved 2.65 million work hours with over 4,000 people helping to build it. MarketContact
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16 Financial results and outlook
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17 Key themes from the financial results FY26 normalised and expected3 EBITDAF of $980m (or $945m after transaction and integration costs), up from the initial $770m in FY25. Improved confidence in the ability to access AGS storage capacity, and the rising value of thermal flexibility, increased the value of the AGS contract and led to the removal of the non-cash provision. TCC and AGS storage enabled Contact to secure ~6PJ of short- term gas from Methanex, supporting renewable generators during dry conditions. New NZAS contract delivered improved pricing, enabled demand response during dry conditions, and provided long-term certainty to support renewable investment.1 1 Net cost of NZAS demand response to Contact in FY25 was $22m. Includes fixed and variable payments to NZAS and the NZAS CFD revenue foregone, net of assumed spot sales. 2 Reported EBITDAF, including AGS onerous contract provision release of $98m, was $872m. 3 Normalised and expected EBITDAF assumes mean hydrology and wind for the year and assumes planned asset availability / capacity i.e. adjusts for planned in-year outages (e.g. geothermal statutory outages, hydro refurbishments). Delivered 1.5TWh of new baseload geothermal from Tauhara and Te Huka 3; Contact’s hydro generation was 15% below mean. Underlying EBITDAF $774m2 ($792m before Manawa-related costs); ahead of normalised and expected EBITDAF. Delivering value from fuel flexibility Delivering value from renewable generation growth
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18 133 151 98 12 663 46 -185 -3 15-46 774 675 -31 872 111 49 71 5 -18 -65 -10 -33 -3235 -43 331 230 261 Profit ($m)1 Performance underpinned by renewable growth, fuel flexibility, and pricing discipline Strong earnings growth reflects investment Underlying EBITDAF ($m)1 Gas and acquired generation costs rose $85/MWh to $200/MWh (+72%), driven by short-term Methanex purchases and NZAS demand response. Market channel pricing up $36/MWh to $186/MWh (+24%), driven by higher realised C&I, CFD and merchant prices in a fuel- constrained market. Renewables up 0.8TWh, with 1.2TWh more geothermal from Tauhara and Te Huka 3 offsetting 0.3TWh lower hydro—reducing reliance on thermal and acquired generation ($200/MWh). Partly offset by a volume mix shift to longer-term sales channels. Opex higher, including transaction and integration costs ($18m) and for new plants online; partly offset by non-cash AGS unwind ($15m). 531 FY25 results: Summary FY24 profit Net interest costs EBITDAF Depreciation & Amortisation Tax Change in FV of financial instruments FY24 EBITDAF 4. Gas, carbon and acquired generation cost 6. Fixed costs FY25 EBITDAF Long-term channel pricing rose $9/MWh to $136/MWh (+7%), reflecting improved NZAS contract terms from 1 July and retail pricing moving closer to long-run expectations. 2 Other income was lower in the period reflecting loss on sale of gas. 6 3. Market channel pricing FY25 profit AGS onerous contract release Underlying EBITDAF AGS onerous contract release (after tax) Underlying profit Realised change in FV of financial instruments Unrealised change in FV of financial instruments 2. Long-term channel pricing 5. Other income 4 1 Movements in profit and EBITDAF are shown on an underlying basis. For FY24, this excludes all impacts of the AGS onerous contract provision—EBITDAF increased by $12m, interest decreased by $5m, tax decreased by $2m, and NPAT increased by $5m. For FY25, underlying figures include the cumulative impact of monthly provision unwinds—EBITDAF increased by $15m, tax decreased by $4m, and NPAT increased by $8m—but exclude $98m from the release of the provision. 2 In FY24, Contact recognised $50m of write-offs, primarily relating to peaker engine damage, Tauhara assets impacted by the 2023 steam hammer event and valve failures, and software assets from discontinued HRIS and CRM projects. In FY25, a further $1 million was written off, relating to capital work in progress and inventory. Asset impairment / write-offs2 1. Renewables and sales volumes
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19 Wholesale EBITDAF1 (underlying, $m) Retail EBITDAF ($m) Corporate / unallocated costs ($m) Operating performance by segment Wholesale business performance offsets retail losses and integration-related costs Refer to slides 20 - 22 Refer to slide 23 68 215 FY24 Generation costs (including acquired generation) Total contracted revenue 3 Trading, merchant revenue and losses FY25 746 895 +149 -32 -49 FY24 0 Electricity Volumes 77 96 Electricity Prices 2 Other products2 0 Opex FY25 -17 Electricity gross margin (-$19m) Electricity and network cost inflation Price recovery 2 Other products includes retail gas and telco gross margins. FY25 results: Segmental performance 1Simply and Western included within Wholesale EBITDAF. Underlying EBITDAF is shown excluding a net $12 million AGS onerous contract provision movement in FY24 and a $98m provision release in FY25. 3 Stats NZ CPI increase over the 12 months to June 2025 plus wage inflation. 4 Net of $4.3m of Manawa transaction costs incurred in FY24. -51 -55 -73 FY24 2 Inflation 2 Growth & performance FY25 before Manawa costs 18 Manawa Transaction and Integration Costs FY25 -22 3 4
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20 Electricity generated or acquired (GWh) Generation costs rose despite strong geothermal growth, reflecting elevated gas and demand response costs FY24 FY25 Electricity generated or acquired costs ($m) Generation costs FY25 results: Wholesale business Gas and diesel Acquired Thermal Renewable Gas storage1 Carbon costs Electricity and gas transmission and levies Other operating costs Generation volumes • FY25 saw two distinct periods of historically low hydro inflows. The result was a reduction in hydro generation of 331GWh (9%) when compared to FY24 and 603GWh below mean (~15% vs 3,900GWh). • Geothermal volumes were up 1,156GWh on FY24 (34%). This increase was a result of Tauhara being operational for the entire period and Te Huka 3 being operational for 2H25. Their 1.5TWh contribution was partly offset by statutory outages at other stations. • While thermal generation was required to support periods of low hydro inflows, particularly in Winter 2024 and Q1 2025, it was down on FY24 by 532GWh as the geothermal stations were online. • While acquired generation was used to help cover supply risk from reduced hydro inflows in FY25, total volume was down 123GWh on FY24. Costs, but not volume associated with the call on NZAS demand response FY25 are captured in acquired generation. Costs • Renewable generation costs were up $23m (18%) on FY24 due to the costs of operating new stations ($7m within opex), geothermal outage acceleration, higher transmission costs and rates. • Thermal generation costs, were up $15m (7%) on increased average cost of gas as a result of short-term purchases in a constrained market (FY24: $8.5/GJ, FY25: $15.4/GJ). • Acquired generation costs were up $29m (31%) despite lower volume. Reflects NZAS demand response payments of $35m2 and no associated volume recognised (FY24: $159/MWh, FY25: $264/MWh). 3,388 4,543 3,628 3,297 1,620 1,088 585 462 FY24 FY25 Acquired Thermal Hydro Geothermal 9,220 9,390 114 134126 34 149 37 218 113 233 143 93 62 122 6127 93 122 5 Generation type Cost type 8 Generation type 14 Cost type 443 443 511 511 +68 81%Renewable % of own generation 88% $48.02/MWh $54.40/MWh 1 Gas storage costs exclude the $12 million net movement in the AGS provision in FY24 and the $98 million provision release recognised in FY25. In FY25, gas storage costs include a $14.6 million provision unwind released throughout the year. Development Acquired generation costs 2 Total payments to NZAS. Does not account for foregone revenue from NZAS on the demand response volume nor any associated sales opportunity.
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21 562 601 163 169 376 471 67 146 113 -11 FY24 45 -9 FY25 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 1,171 1,386 +215 3,689GWh $162.9/MWh Contracted revenue ($m) Diversified mix of long-term and ASX linked sales channels 2,297GWh $204.9/MWh -112GWh +$15.15MWh -276GWh +$58.6/MWh Contracted wholesale revenue increased across most channels, supported by higher prices and strategic volume shifts. • Sales to the retail segment were 112GWh lower than FY24, with warmer conditions reducing usage per connection. The electricity transfer price rose by $15/MWh to $163/MWh—reflecting higher wholesale prices over the past three years—resulting in a $39 million increase in revenue. • C&I channel sales were marginally higher in FY25 (+41GWh) with fueling limitations in Winter 2024 and early 2025 reducing the ability to sell additional volume in the period. Net price improved slightly (+$0.2MWh) reflecting customer contracts repricing closer to the prevailing ASX price during the period. • CFD volumes fell by 276GWh as more sales volume was allocated to long-term strategic channels. This was partly offset by a large risk management contract sold to Meridian in 1H25. CFD pricing rose by $58.6/MWh to $205/MWh, reflecting the market conditions. • Strategic fixed price volumes rose by 508GWh, driven by new PPAs linked to Tauhara and higher contracted volumes to NZAS. This was partly offset by NZAS demand response during the period. Pricing for these sales increased by $29.5/MWh, reflecting both the Tauhara-backed PPAs and a full year of sales under the new NZAS agreement effective 1 July 2024. • Other income was lower due to a loss on gas sales, driven by a materially higher weighted average cost of gas following purchases from Methanex in early FY25. Wholesale contracted revenue 1,170GWh $144.1/MWh +41GWh +$0.2/MWh FY25 results: Wholesale business 1,727GWh $84.7/MWh +508GWh +$29.5/MWh Year-on-year changes to volume and price FY25 volumes and price
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22 Trading EBITDAF ($m) Long / short position (GWh) $178.4/MWh 4.8% ($8.5 / MWh) 9.0% ($7.4 / MWh) In FY24, hydro volatility and elevated spot prices led to reduced hydro generation and increased reliance on higher-cost thermal, resulting in lower merchant generation compared to FY23. This trend continued in FY25, with merchant generation remaining broadly flat year-on-year. FY25 conditions were shaped by: • Historically low hydro inflows, significantly reducing hydro output. • Lower wind generation, compounding the supply gap. • Elevated wholesale spot prices throughout the year. • Significant demand response from NZAS, helping reduce system demand during tight periods. • A shift away from merchant exposure, as short-dated electricity sales contracts were used to de-risk material gas arrangements. The LWAP/GWAP spread widened to 9%, reflecting volatile market conditions, including periods of higher South Island prices and periods where generation at thermal nodes was concentrated (suppressing pricing). 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 $197.9MWh Spot purchases and sell CFD settlement Spot sales and buy CFD settlement Merchant generation 91 100 -73 -80 FY24 FY25 18 20 513 507 8,707 -8,707 FY24 8,883 -8,883 FY25 513 507 FY25 results: Wholesale business LWAP/GWAP losses
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23 1 Retail business performance EBITDAF ($m) Managing through rising wholesale input costs while growing market share through a multi -product strategy Revenue & Tariff1 ($m) FY25 FY24 Variance $m Tariff $m $m Tariff Electricity revenue 1,079 $312/MWh 1,018 61 +$25/MWh Gas revenue 103 $49/GJ 96 7 +$8/GJ Telco revenue 101 $72/Mth 82 19 - Other income 7 10 -3 Total revenue 1,290 1,206 84 Contract Asset (closing) 3 3 0 # of connections (closing) 1 642k 621k Cost to serve/connection2 $116 $123 1 Retail connections only, excludes Simply Energy. 2 Reflects total operating costs (direct and indirect) / average connections. Includes customer acquisition costs. 10 13 8 18 17 7 -11 -74 -74 FY24 FY25 Other Gas GM Electricity GM Telco GM Other operating expenses -32 -49 4 -17 Gross Margin (GM) is Revenue less Cost of Goods (Networks, meters, levies, energy, carbon and telco) 3 Input costs shown per MWh at the GXP. FY25 results: Retail business Retail margins have contracted, driven by sustained high wholesale prices and rising distribution costs. • Retail EBITDAF decreased by $17m on FY24 largely driven by the $96m increase in electricity input costs that were not fully passed through to customers. The average retail electricity tariff increased by 8.8% reflecting targeted retail price rises to partially offset rising wholesale costs and full recovery of lines cost increases. • Around 91% of customers received a price increase in the last 12 months. As the energy industry decarbonises, cost pressure for retailers is expected to remain, including: • Significant investment in lines and distribution infrastructure.4 • Continued elevated wholesale futures prices. This will result in an increase in the cost that consumers will pay over the coming years. Connections grew strongly since 2H24 particularly through telco and Time of Use (ToU) electricity Good plans, with a focus on multi- product customers. • Total connections +21k on FY24 with telco up 15k and energy up 6k. • Multi-product customers up 7% on FY24, driven by strong telco product attachment alongside ToU Good plans growth. Cost to serve – reduced by $7/connection, largely driven by increased connections, lower marketing spend and productivity improvements through continued growth in digitised interactions, partially offset by wage inflation. 73k 109k 439k FY24 73k 124k 445k FY25 Gas Telco Electricity 621k 642k Closing connections (k) Electricity transfer price3 $148/MWh $164/MWh Networks, meters and levies3 $118/MWh $132/MWh 4 From 1 April 2025, Commerce Commission-approved changes to network charges began to take effect, increasing household bills by $10–$25 per month on average (depending on region and usage profile).
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24 Other operating cost movement ($m) Base movement Non-recurring and performance items • FY24 included $4 million of one-off costs related to assessing the Manawa acquisition (in addition to costs for cyclone repair and restructuring). • In FY25, non-recurring spend outside of Manawa included feasibility costs for the Wairakei extension, SAP Ariba implementation and restructuring. FY25 saw an increase in employee incentives, reflecting strong performance outcomes. Base movement • General inflation contributed approximately $3 million (2.7%). However, several key cost categories rose faster than inflation: • Labour costs increased by 3.5%, including $5 million for staff development under the Grow Your Whānau parental support programme. • Rates rose by 36% ($1 million). • Staff benefit costs higher—including medical insurance, electricity subsidy support, and increased retirement contributions— to support capability retention. • Insurance costs increased by 20%, although this was partly offset by changes to the insurance programme structure. • Productivity improvements in the Retail and C&I businesses helped mitigate some of these cost pressures. Growth • Retail connection growth added $1 million in operating costs. • Tauhara and Te Huka 3 contributed $7 million in additional operating expenditure. • A further $2 million was invested in feasibility work for future geothermal, wind, and solar development. Operating costs reflect inflation, growth, and one- off items related to the Manawa acquisition General cost inflation Growth FY25 results: Other operating costs HeadwindsFY25 One-off Impacts FY24 One-off Impacts 5 10 11 10 7 2 4 Non-recurring 3 0 Base movement Growth Underlying Opex FY25 Manawa Related Costs FY25 Reported 253 0 13 276 18 294 FY24 Non-recurring and performance Productivity savings Manawa Costs FY25 Performance Integration Costs Transaction Costs
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25 • Higher underlying EBITDAF, as detailed on slide 18. • Working capital change was a negative $35m impact to OpFCF (vs. positive $31m in FY24), mainly due to increased gas inventory purchases—both in volume and cost per GJ. • Tax paid was $9m higher, reflecting stronger operating profit and the July 2024 final wash-up payment for FY24. • Interest paid, net of capitalised interest, rose by $56m. This was driven by the commissioning of Tauhara, which reduced the amount of interest eligible for capitalisation compared to FY24. 12 months ended 30 June 2025 12 months ended 30 June 2024 Comparison against FY24 EBITDAF (underlying) $774m $663m ↑ $111m Working capital changes ($35m) $31m ↓ ($66m) Tax paid ($106m) ($97m) ↓ ($9m) Interest paid, net of interest capitalised ($77m) ($21m) ↓ ($56m) SIB capital expenditure1 ($110m) ($156m) ↓ $46m Non-cash items included in EBITDAF ($12m) $4m ↓ $16m Operating free cash flow1 $434m $424m ↑ $10m Operating free cash flow per share 54.4 c 53.9 c ↑ 0.5 c Cash conversion (OpFCF / underlying EBITDAF) 55% 64% ↓ down 9% Return on invested capital (ROIC) Cash conversion lower with strong EBITDAF growth offset by negative working capital changes and interest Cash flow and capital expenditure Sources and uses of cash ($m) FY25 results: Cash flow 146 200 174 96 251NOPAT - $m 1 Pre-FID costs associated with Te Mihi Stage 2 have been reclassified as SIB capex in FY24 ($46m). These were previously allocated to growth capex. FY24 operating cash flow has been adjusted accordingly. 2 NOPAT is calculated as annual EBIT less tax (tax includes annual tax expense and movements in deferred tax over the year as a proxy for cash tax paid). Invested capital is calculated as the average of the opening and closing balance of: net working capital (adjusted to remove current borrowings, current net derivatives and excess cash above $50m) + non-current assets (adjusted to remove non-current derivatives). The ROIC calculation includes the after-tax movement in the AGS provision over time. In FY25 this amounted to a $71m benefit in the NOPAT figure. 3 ROIC average is calculated as NOPAT (4-year average) / Average IC (4-year average). 4 ROIC (FY) is calculated as Annual NOPAT (FY) / Average IC (FY). 434 309 110 285 60 473 Sources 13 361 43 Uses 1,017 1,017 Cash Used Debt drawdown OpFCF Dividend re-invested (DRP) Sale of asset Strategic investments / acquisitions Growth investment Dividends paid Financing costs Realised losses on market derivatives 0 1 2 3 4 5 8 9 3.6% 3.7% 3.7% 3.3% 3.7% 4.9% ROIC (average)3 ROIC (FY)4 475 Net operating profit after taxes (NOPAT) / Invested capital (IC)2 Average IC ($m) 4,575 4,482 4,518 4,874 5,349 5,670 FY20 FY21 FY22 FY23 FY24 FY25
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26 Growth capital expenditure 1 Excludes ~$1m of development capex that has been approved to advance Manawa projects in FY26. 2 Total under current board approvals. 3 For Te Mihi Stage 2, the board approved an additional $49m contingency (over and above the contingency amount already included in the expected and approved total construction cost of $712m) to account for a scenario where a broader range of risks materialise and to ensure prudent balance sheet management. If called on, this would take the total cost to $761m. 4 Relates primarily to Western coil tube drilling and deployment of demand flex technology. 5 Relates to Te Mihi Stage 2 and Glenbrook-Ohurua BESS development. 6 Excludes pre-FID development expenses for solar which are captured within receivables. Growth capital expenditure – cash basis ($m)¹ Up to 30 June 2024 12 months ended 30 June 2025 Remaining under current approvals Total² Tauhara $852m $53m $26m $931m Te Huka 3 $246m $47m $12m $305m Te Mihi Stage 2 $57m $144m $511m $712m3 Wind $13m $8m $5m $26m Glenbrook-Ohurua BESS $5m $87m $71m $163m Other4 $17m $2m $3m $23m Capitalised interest $173m $23m $70m5 $266m Total $1,363m $363m $697m $2,425m Contact’s FY25 growth investment demonstrates progress in the strategic execution of its renewable development pipeline • Construction commenced in FY25 on three major renewable projects: the Glenbrook-Ohurua Battery Energy Storage System (BESS), the Kōwhai Park solar farm, and the Te Mihi Stage 2 geothermal plant. • The totals shown reflect board-approved funding and include pre-FID sunk costs of $66 million for Te Mihi Stage 2 geothermal and $5 million for the Glenbrook-Ohurua BESS. • Construction of the Tauhara and Te Huka 3 geothermal plants is now complete. Remaining spend on Tauhara relates to planned works during its first statutory outage in November 2025. For Te Huka 3, the remaining spend reflects final milestone payments due post-completion. • Contact does not currently have any wind projects under construction. The reported wind development spend reflects pre-FID activity only. • For major growth projects, Contact capitalises interest from the point of FID—or from the commencement of significant pre-FID works—through to commissioning. The capitalisation rate reflects the average interest rate across the portfolio. • Contact’s investment in the Kōwhai Park solar farm is accounted for as an investment in joint ventures and associates, and is therefore excluded from growth capital expenditure. Up to 30 June 2024 12 months ended 30 June 2025 Remaining under current approvals Total² Solar6 - - $37m $37m C02 $2m $5m $1m $7m Forestry $44m $39m $1m $84m Total $45m $43m $39m $128m Investment in joint ventures and associates ($m) FY25 results: Cash flow
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27 Approach and FY25 highlights • Contact’s capital management strategy is anchored to maintaining an investment grade credit rating, which is supported by a net debt to EBITDAF sustainably below 3.0x. At FY25 year-end, the point estimate of net debt to EBITDAF was 2.3x. • During FY25, Contact issued a NZ$250 million Capital Bond and a A$400 million Australian Medium Term Note (AMTN). Both instruments were certified Green under the Climate Bonds Initiative framework and support the funding of Contact’s renewable development pipeline. Looking ahead • Following the completion of the Manawa acquisition on 11 July 2025, Contact raised NZ$900 million in new bank debt. This was used to repay Manawa’s existing bonds (NZ$388 million), settle bank facilities, and fund the cash consideration paid to Manawa shareholders. • It is expected that the Manawa acquisition will increase net debt to EBITDAF in the near term and it may temporarily lift above 3.0x. However, it is expected to return below the threshold as the benefits of the acquisition are realised. Contact’s diverse funding sources enable continued renewable build Closing net debt ($m) Face value of borrowings less cash Interest rate (%) Weighted average gross interest2 on average borrowings Net debt to EBITDAF (x) Includes S&P adjustments3 Borrowing maturities ($m) Average tenor of 7.7 years as at 30 June 2025 Supportive balance sheet 1 Includes $87m (FY24) and $0m (FY25) of collateral held on deposit for margin calls associated with the trading of electricity price derivatives on the ASX. Includes $180m of commercial paper (FY25) not shown in borrowings breakdown (right). 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 expected S&P adjustments. See breakdown of S&P approach on slide 51. 774 1,025 1,474 1,831 2,314 -514 22 -44 FY20 21 -150 FY21 25 -168 FY22 49 -140 FY23 47 -229 FY24 50 FY251 1,014 645 882 1,383 1,649 1,850 1,036 Lease obligations Borrowings Cash on hand 67 434 435 225 250 135 150 300 250 350 350 7 FY26 7 FY27 224 FY28 FY29 FY30 FY31 FY32 FY52 FY55 142 157 625 717 Undrawn bank facilities Domestic bonds USPP NEXI Capital bonds AMTN 2.4 1.4 1.8 2.6 2.7 2.3 FY20 FY21 FY22 FY23 FY24 FY25 974 892 5.2% FY20 5.2% FY21 5.4% FY22 5.8% FY23 6.1% FY24 5.8% FY25 1,029 1,310 1,727 1,973 Average gross interest Average gross debt FY25 results: Key balance sheet metrics 1
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28 Dividend for FY25 of 39 cents per share • The final dividend of 23 cents per share is imputed up to 57% or 13 cents per share for qualifying shareholders. • This takes the total FY25 dividend declared to 39 cents per share, representing a pay-out of 82% of FY25 operating free cash flow and 101% of the average operating free cash flow over the preceding 4 financial years (FY21-FY24). • The record date is 26 August 2025; payment date is 24 September 2025. • The NZD / AUD exchange rate used for the payment of Australian dollar dividends will be set on 3 September 2025. Dividend per share for FY25 39cps, up 5% 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. • A 2% discount will be offered for the FY25 final dividend and Contact will have the right to terminate or suspend the plan at any time. • Dividend reinvestment plan application forms must be in by 27 August 2025 to confirm participation in the plan. • The trading period for setting the price for the DRP is 25 August 2025 to 29 August 2025. The DRP strike price will be announced: 1 September 2025. Ordinary dividends ($m) Declared Final dividendInterim dividend % pay-out of annual operating free cash flow 35 35 35 37 39 83% 97% 68% 82% Operating free cash flow Average operating free cash flow for the preceding four financial years Contact’s dividend policy is to pay dividends of 80-100% of average operating free cash flow of the preceding four years. As the historic measure will not capture the operating free cash flow contribution from Manawa within the history, the Board will apply discretion in the first few years post-acquisition, if the measure is temporarily above 100%, so that it is not constrained in delivering the expected DPS uplift. This has been the approach taken in FY25. If the shares issued as consideration for Manawa are excluded, the FY25 dividend declared would represent a pay-out of 72% of FY25 operating free cash flow and 89% of the preceding 4-year average. 309 247 FY21 326 261 FY22 333 266 82% FY23 318 256 92% FY24 352 282 101% FY25 371 330 282 ➢ Annual operating free cash flow 100% 80% Dividend level as a % of preceeding 4yr operating fcf 163 164 165 181 227 109 109 109 110 128 FY21 FY22 FY23 FY24 FY25 272 273 274 291 355 cps 73% 424 434 1 All dividend decisions are a matter for the Board at the conclusion of each reporting period. These align to the dividend policy and are dependent on business and market conditions when each payment decision is made. Dividend expectations • Contact indicated that it expects to lift the total dividend in FY26 to 40cps and between 41 and 42cps in FY27.1 ‒ On this basis, dividends in FY26-FY27 are expected to be imputed up to ~80%. • Reliable ordinary dividends are expected to increase over time with growth in operating free cash flow. Reflects 101% of the average operating free cash flow for the preceding four years
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29 Normalised and expected FY26 EBITDAF $980m1 Before Manawa transaction and integration costs and assuming mean hydrology and wind conditions Strategic fixed price 3,960GWh $95/MWh $376m CFDs 1,700GWh $155/MWh $264m C&I 1,750GWh $165/MWh $289m Retail 3,825GWh $164/MWh $627m Other income4 $100m $1,656m Hydro mean 5,750GWh $0/MWh -$0m Geothermal average 4,950GWh $4/MWh -$20m Thermal 275GWh $215/MWh5 -$59m Renewable PPAs 830GWh $100/MWh = -$83m Acquired 200GWh x $260/MWh6 = -$52m -$214m Length7 $139m Transmission/Storage -$90m Location losses8 -$140m Opex underlying (including in-year synergies) -$370m Opex - Integration & transaction costs -$35m Total Opex -$405m Total $-1m Total -$495m 2. All volumes are at the Grid Exit Point (GXP). 3. Net price is equal to tariff less pass-through costs (network, meters and levies) /MWh. 4. Steam sales, retail gas gross margin, telco gross margin and other income. ASSUMPTIONS FOR NORMALISED EARNINGS 5. Gas price of $16/GJ, carbon price of $80/unit and thermal portfolio heat rate (10.5GJ/MWh). 6. Acquired generation price includes premiums paid for HFO (operational from 1 Jan 2026), and NZAS demand response. 7. Length of 770GWh p.a. assumed. 8. Locational losses of 6.5% on spot purchases and settlement of CFDs sold at a wholesale price of $180/MWh. * Fuel is natural gas and carbon costs. 1,046 654 Channel choices maximise long term value21 Net price3 driven by best commercial practices2x = FY assumptions that deliver expected & normalised EBITDAF for FY26 Fuel cost Net Revenue Trading Fixed costs Hydrology & Asset availability optimise generation3 4 Totalx = Access to and price of fuel* drives financials & risk position Total x x x x x x x = = = = = = 1,535 215 3,825 3,960 CFDs C&I Retail Strategic fixed $155/ MWh $165/ MWh $164/ MWh** Contracted Uncontracted 1,656 -214 -90 -370 -1 -35 945 x 153 150 160 123 219 219219 247 247 247 142 133 140 111 140 183 183 223160 147 Aug- 25 Sep- 25 Oct- 25 Nov- 25 Dec- 25 160 Jan- 26 Feb- 26 Mar- 26 Apr- 26 May- 26 Jun- 26 ASX Futures $/MWh At 6 Aug 2025 $95/ MWh OTA monthly OTA Quarterly BEN Monthly BEN Quarterly 1. Normalised and expected EBITDAF assumes mean hydrology and wind for the year and assumes planned asset availability / capacity i.e. adjusts for planned in-year outages (e.g. geothermal statutory outages, hydro refurbishments). = Trading delivers value to largely offset locational losses5 Digitalisation & continuous improvement optimise fixed costs6 Reported basis Includes $35m integration and transaction costs Opex (underlying) Opex (integration and transaction) $m ** Retail volume contracted. Competitive risk remains on pricing achieved. Note: All figures are subject to rounding. GWh:
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30 Update on Manawa and strategic delivery
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3131 Recap: A strategically compelling acquisition Combined portfolio will see mean renewable generation of more than 11TWh2 with ~98% renewable output2, accelerating Contact’s strategy to grow renewable generation while decarbonising its portfolio. 1 Geographically diversified hydro schemes are complementary, enhancing portfolio resilience and the volume of fixed price supply agreements able to be placed into the market.1 2 Hydro flexibility is expected to provide firming to expedite intermittent renewable development. 3 Highest value options can be advanced from an attractive and diversified combined development pipeline, supported by Contact & Manawa’s renewable development execution capabilities. 4 1 When compared to the volume that can be supported by Contact’s and Manawa’s standalone hydro portfolios. 2 Based on long term average hydrological conditions and an expectation of 200GWh to 300GWh of gas generation through the Strat ford peakers following the planned closure of the Taranaki Combined Cycle gas plant in late 2025. Excludes any short-term acquired generation purchases e.g. fuel replacement via ASX which will reflect the renewable mix of the market. 0.6 0.8 1.0 1.2 1.4 1 2 3 4 5 6 7 8 9 10 11 12 Seasonal shape Monthly averages (2007-2023) Manawa Contact Output relative to average (x) 0.8 0.9 1.0 1.1 1.2 1.3 2007 2009 2011 2013 2015 2017 2019 2021 2023 Manawa Contact Volatility and generation shape over time Output relative to average (x) Average Average Jan Feb Mar Jun Jul Sep Oct Nov DecApr May Aug
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32 Delivering on the promise of the Manawa acquisition Contact is well-positioned to deliver the benefits of the Manawa acquisition, backed by market tailwinds and a proven integration approach Re-cap: Expected benefits on transaction announcement (EBITDAF)1 Status Key changes Cost synergies $23m – $28m 100% within 18-24 months Generation normalisation ~$11m MCY, PPA & C&I contract rollover ~$21m Expected portfolio benefits $10m - 20m Embedded value – Future Manawa standalone earnings potential ✓ On track ✓ On track ✓ On track ✓ On track Continued integration plan refinement has underpinned confidence in cost synergies ➢ Targeting $25m - $28m operating cost reduction ➢ Targeting $26m - $29m cash opex and financing cost synergies ➢ 100% within 12-18 months (exit run-rate) Key milestones met in Manawa asset refurbishment programme ➢ Matahina upgrade completed in FY25 (17GWh mean annual uplift) ➢ On track to achieve mean annual hydro generation of 1,991GWh from FY28 Contact’s view of long-term wholesale prices remains $115 to $125/MWh2 ➢ Benefit of ~$21m is a long- term estimate i.e. no change ➢ Near-term upside from ASX electricity futures uplift since announcement Emerging market trends support future quantified and non-quantified portfolio benefits Widening of winter / summer ASX electricity futures pricing gap since announcement (up >20%) ➢ Value shift to flexibility 1 Expected EBITDAF benefits as presented at announcement on 11th September 2024 – Shown with reference to Manawa’s FY24 EBITDAF (March year end). 2 Real 2025. This is a through-the-cycle measure in a balanced market. Prices achieved are a function of the market at a point in time.
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33 ASX Futures (Quarterly, base period, OTA)3 $/MWh Increase in electricity futures prices expected to provide higher near-term hedge repricing benefits 1 Represents incremental annual output delivered by the programme. Assumes mean hydro and a 2021 baseline. 2 Phased uplift to occur from FY26. Winter 2026 and winter 2027 ASX futures up >20% vs. announcement 80 100 120 140 160 180 200 220 240 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 1,576 457 1,079 825 576 326 250 869 748 1,001 1,251 1,500 1,750 500 0 500 1,000 1,500 2,000 FY26 FY27 FY28 FY29 FY30 FY31 76 FY32 Roll-off (cumulative) ASX-linked4 Fixed price (set 2021) + CPI GWh +21% +22% Key milestones met in Manawa’s asset refurbishment programme: On track for 1,991GWh p.a. mean output from FY28 Project Status Uplift (GWh)1 Branch Completed 10 Matahina Completed 17 Waipori Completed - Cobb Completed - Arnold Completed - Various Completed 20 Highbank On track – FY27 8 Coleridge On track – FY282 23 Total 78 47 12 14 59 72 78 0 20 40 60 80 FY22-FY25 FY26 FY27 6 FY28 Hydro uplift over time – approved projects1 (30 June year end) Hydro improvement project status Asset upgrades and market tailwinds building confidence Current At announcement Completed (cumulative) On track Mercury hedge volume (30 June year end) 3 ASX NZ Electricity Otahuhu base quarter futures pricing as at 30 July 2025. 4 Pricing linked to historic rolling ASX prices from 1 October 2026. Volume is winter-weighted (60% / 40%; winter / summer) CY 2026 CY 2027 CY 2028 GWh
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34 Cost synergies on track Opex reduction target: In-year benefit $m FY26 FY27 Opex reduction target: Exit run-rate $m FY26 FY27 FY26 FY27 Integration costs (opex)1 $m Integration Management Office (IMO) established….. A well resourced integration management programme is in place 6 Integration management workstreams 9 Functional workstreams ~70 Initiatives Executive sponsorship for each workstream and initiative IMO accountabilities: ▪ Ensure a smooth transition for teams, systems, and operations. ▪ Achieve ~70% of targeted cost reductions within the first six months (exit run-rate basis). ▪ Deliver the full value of the acquisition, including cost synergies. ▪ Guide the organisation through its transition to the future operating model. …..with granular plans firming up targets for cost synergies Cost reduction targets confirmed (all shown pre-tax) Opex reduction target at announcement: Opex reduction target now: $23m - $28m 100% within 18-24 months post completion (exit run-rate) 100% within 12-18 months post completion (exit run-rate) $26m - $29m Cash opex and financing cost synergy target: 100% within 12-18 months post-completion (exit run-rate) 33 – 37 20 – 25 10 – 15 10 – 20 23 – 27 Expected combined operating costs FY26 $m $m Opex reduction (in-year benefit) 10 – 20 Less: Integration costs within opex1 (20 – 25) Less: Transaction costs within opex (13) Total operating costs (400 – 410) 1 Approved integration costs (both opex and capex) total $45m over FY25 to FY27 ($7m has been incurred in FY25) with an additional $9m contingency. The ultimate allocation between opex and capex is dependent on accounting treatment and is yet to be confirmed. $25m - $28m 22 – 25 25 – 28
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35 Upside from portfolio combination benefits to come Since the acquisition announcement, updated New Zealand gas reserve data shows a decline of more than 20% in forecast production for each year through to 2030, relative to 2024 estimates.1 Limited gas availability and rising costs have pushed the marginal cost of thermal generation above $200/MWh. Material downgrade to gas field reserves Supported by market trends… … which are expected to grow the portfolio combination benefits Winter Summer Price Separation Widening Value shift to flexibility While average prices continue to reflect long-run economics, ASX Futures show winter prices rising significantly faster than summer prices. This trend is driven by the need to recover higher thermal fuel costs and the growing share of must-run renewables in the market. Futures for winter 2026 and 2027 are now up >20% compared to levels at the time of the acquisition announcement. We expect market value to increasingly favour operators of flexible, intra-day assets and those with fuel storage—rather than intermittent renewable generators. Combined inflow characteristics Increasing importance of flexibility More efficient participation in spot market How is it captured? Quantification (2025, Real, $m) 1 3 • Portfolio diversification reduces risk. • Increased fixed-price sales enhance revenue certainty. • Greater flexibility in managing stored fuel (eg AGS and Hydro). • Reduced generation costs through avoided gas use. • Lower spend on risk management products (e.g. HFO). • Improved arbitrage margins from battery storage (BESS). • Higher generation-weighted average price (GWAP). • Increasing GWAP:TWAP ratio for key flexible assets over time. Benefits quantified and included in acquisition evaluation ✓ ? Not included in acquisition evaluation. Benefits present future upside potential • $10m - $20m, mid-point $15m targeted FY272 • $5m targeted FY262 • n/a Focus on capturing the benefits of increased generation flexibility, increased access to renewable winter energy and reducing hydrology risk • Initial coordination in place from Day 1 through existing communications and processes. • Gradual integration of dispatch operations across both portfolios. • Enhanced real-time decision-making to optimise dispatch across all assets. Steps to achieve 1 Source: MBIE 2P reserves data published 5 June 2025; Contact analysis. 2 This is a through-the-cycle measure. Actual result will be impacted by hydrology, fuel and other market conditions. • Unlock further flexibility and improve monetisation with improved trading of assets. 2
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36 Combined portfolio 98% renewable from FY26 (mean wind and hydro) 1 Final commissioning activities were ongoing at the illustrated online dates for each of Tauhara and Te Huka 3. Those commissioning activities were completed in FY25. 2 The uplift of 78GWh p.a. is on a 2021 base and assumes mean hydrology. As at 30 June 2025, asset refurbishments have been com pleted delivering 47GWh p.a. of this uplift, with work continuing on the 31GWh p.a. remaining. See slide 33. 3 FY25 generation figures reflect actual volumes in FY25. FY26 and FY28 volumes assume mean hydro and wind generation and account for planned hydro outages (refurbishments) and the geothermal statutory outage schedule. See slide 47. 4 Other geothermal volume excludes geothermal PPA purchases due to the near-term completion of the contract (December 2026). Summary of renewable projectsdelivered and underconstruction Expected generation (indicative): Indicative output by source over time (TWh)3 Existing plant and committed projects only: 1.0 0.6 1.3 0.9 2.3 1.4 2.6 3.3 1.1 5.8 FY25 0.3 FY26 8.9 11.6 +30% 100MW/200MWh Glenbrook-Ohurua BESS Other renewable electricity assets available by FY28 Wind (PPA) Tauhara online1 Te Huka 3 online1 Te Mihi Stage 2 (0.8TWh) Wairakei Partial closure (-0.6TWh) Glenbrook- Ohurua BESS (100MW)Roxburgh hydro (45GWh p.a. mean uplift) Kōwhai Park Solar (0.3TWh) 2024 2025 2026 2027Calendar year Delivered Under construction Manawa hydro asset refurbishments (78GWh p.a. mean uplift)2 Renewable output: 88% ~98% Annual mean renewables to support electricity sales to be above 12TWh per annum from FY28 0.6 2.2 2.5 5.9 0.2 0.2 0.5 FY28 12.1 ~98% Wairakei station Te Mihi Other geothermal4 Solar Hydro Thermal Chart excludes short-term acquired generation purchases e.g. fuel replacement via ASX which will reflect the renewable mix of the market
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37 Development prioritised as the market requires Grid connection and transmission Ease of consent; Ease of construction Quality of resource; Capacity factors Development options across Contact and Manawa’s integrated pipeline will be prioritised and advanced based on key strategic evaluation criteria and guiding capital allocation principles Location and shape vs. demand Portfolio diversification and fit Relative cost; Funding model Key strategic evaluation criteria for renewable projects Invest to deliver value accretive growth • Returns improved through prioritisation of non-equity funding. • Projects ranked consideringreturns available and overall portfolio implications. • Allocate capital to strategic priorities, with an ability to scale down in downside scenarios. Optimise existing operations and manage risk • Reduce carbon exposure and manage market volatility during the thermal transition. • Disciplined approach to sustaining capital spend. − Efficient deployment of stay-in-business capital expenditure. • Strong operating cash flow. Continue to attract capital • Deliver competitiveshareholderreturns including dividend commitment. − Reliable ordinary dividends that increase in line with growth in cash flow. − Pay-out ratio of 80-100% of average operating free cash-flow over the preceding 4 years. • Balance sheet strength with investment grade credit metrics through the cycle. − Target BBB <3x net debt to EBITDAF. − If temporarily above, always have clear plan to restore metrics. Recap: Contact’s guiding capital allocation principles Considering supportive market conditions and a broad range of attractive projects post Manawa acquisition, we will prioritise investments to grow shareholder value and distributions Strategic evaluation criteria are used to prioritise development options that will offer the most attractive returns on investment; prioritised projects compete under our capital allocation framework
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38 Project Capacity (MW)1 Estimated output (GWh) Expected online date Earliest available investment timing / decision2 Project status Land secured Consent lodged Consented Under construction Contact Committed Kōwhai Park Solar 168 275 Q2 CY2026 Glenbrook-Ohurua BESS 100 n/a Q1 CY2026 Te Mihi Stage 2 101 840 Q3 CY2027 Assessing Glorit Solar 170 280 FY26 Glenbrook BESS 2003 2003 n/a FY26 Southland Wind4 326 1,210 FY27 Strafford BESS5 100 n/a FY27 Stratford Solar 180 300 FY27 Other solar 700 1,155 Various Other wind 685 2,470 Various Other geothermal6 TBC ~1TWh >FY28 Manawa Assessing Argyle 1 & 2 90 177 FY26 Kaipara 113 190 FY27 Huriwaka 300 890 FY27 Hawke's Bay Airport 45 80 FY27 Kaihiku (JV)7 300 1,060 FY27 Hapuakohe 230 710 FY28 Mackenzie Basin 283 540 FY28 Ototoka 150 530 FY29 Marlborough Wind 100 330 FY29 Development options across a diverse combined pipeline of >10TWh An attractive and diversified development pipeline 1. Capacity for solar projects is shown as MWp. 2. All available FID timings are to be confirmed. 3. Indicative sizing at FID. Consent application filed for 400MW new capacity, providing future optionality. 4. Based on 6MW turbines. Turbine size is to be confirmed. 5. Capacity of 100MW consented. Preparing to seek consent for additional capacity. 6. Reflects uplift in output available from Tauhara Stage 2 and Te Mihi Stage 3 from consented fluid take. 7. Kaihiku is a 50:50 JV with 300MW total capacity. Solar options Wind options Land access secured Consenting underway Consented 7TWh 3TWh Combined solar and wind pipeline options of >10TWh
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39 Our operational plan for the next 12 months FY26 Achieve FID for CO2 Glenbrook-Ohurua BESS online Q1 CY2026 Kōwhai Park solar online Q2 CY2026 Te Mihi Stage 2 geothermal on track for online Q3 CY2027 Close TCC gas generation plant late CY 2025 Scope 1 & 2 emissions <650ktCO2e2 Multi-product customers >156k (up from 149k) Cost to serve <$116/connection3 Grow renewable development Decarbonise our portfolio Create outstanding customer experiences Strategic theme Grow Demand Subject to market conditions and obtaining consents, achieve FID on: ▪ Solar (e.g. Glorit, Argyle); and/or ▪ Glenbrook 200 BESS New demand facilitated since FY21 to reach >250MW1 At least 50% of new demand contracted in-year structured with favourable shape (considering load and generation) Sustained New Zealand leadership position in the Asia Pacific DJSI Next update on strategy will be provided at Contact’s November 2025 Capital Markets Day Manawa integration In-year benefits target: ▪ Opex reduction $10m to $20m ▪ Portfolio benefits $5m4 Targeting net price up by ~2% Exit run-rate benefits target: ▪ Opex reduction $22m to $25m ▪ Portfolio benefits $10m to $20m4 Consents lodged on at least 2 renewable development projects 1 Cumulative measure (~230MW as at 30 June 2025). Shown on a total contracted basis. 2 Assumes mean hydrological conditions. 3 Excludes customer acquisition costs. 4 This is a through-the-cycle measure. Actual result will be impacted by hydrology, fuel and other market conditions.
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40 Questions
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41 Supporting materials
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42 Guidance topics FY25 guidance FY25 result FY26 guidance FY26 Guidance Commentary Stay in business (SIB) capex (cash) $120-130m $110m $175m - $190m SIB capital expenditure BAU $77m - $87m $71m $115m - $125m At the mid-point ~$5m higher than long-run expectations due to consenting. SIB accelerated programme ~$40m $36m $12m - $13m Close-out of Contact’s $150m accelerated capex programme announced 2021. SIB capital expenditure Wairakei $2m - $3m $3m $20m - $25m Wairakei extension costs. SIB capital expenditure enhancements and integration na na $23m - $27m Geothermal wells (~$8m), Manawa hydro refurbishment (~$12m) and integration. Growth capital expenditure (cash)1 $450m - $550m $363m $390m - $400m Growth capital for Tauhara, Te Huka 3, Te Mihi Stage 2, Wind and BESS projects. Depreciation and amortisation $275m - $285m $273m $280m - $290m Reflects useful life changes on thermal assets, introduction of Tauhara and Te Huka 3 as well as Manawa expected depreciation. Net interest (accounting) $105m - $115m $100m $145m - $165m Reduction in capitalisation of interest with Tauhara commissioning. Higher interest rate environment and increased borrowings with Manawa acquisition. Cash interest (in operating cash flow) $85m - $95m $80m $135m - $155m Cash taxation $105m - $115m $106m $130m - $140m FY26 provisional payments based on FY24 results and higher final tax payment relating to FY25. Includes estimated Manawa tax payments. Realised (gains) / losses on market derivates not in a hedge relationship $15m - $20m $13m $10m - $15m Including (gains) / losses on ASX market making. Corporate costs - ex Manawa $54m $55m $55m Reflects Contact corporate costs only. Manawa corporate costs are all allocated to wholesale. As integration progresses, allocations may be updated. Corporate costs - Manawa integration and transaction $20m $18m $30m - $40m Non-recurring costs relating to the Manawa acquisition. Target ordinary dividend per share 39 cps 39 cps 40 cps Increase in the ordinary dividend to reflect benefits of the Manawa acquisition Operating cash flow conversion 50% 55%2 ~50% Higher interest costs as investments come online (meaning lower capitalised interest) and reflecting Manawa debt. Working capital to support HFO. 1 Growth capital expenditure includes capitalised interest. 2 Based on $774m underlying EBITDAF.
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43 Strategic fixed price 1,900GWh $80/MWh $152m CFDs 1,770GWh $154/MWh $273m C&I 1,300GWh $150/MWh $195m Retail 3,800GWh $154/MWh $585m Other income³ $47m $1,252m Hydro 3,900GWh $0/MWh -$0m Geothermal 4,620GWh $4/MWh -$19m Thermal⁴ 350GWh $130/MWh4 -$46m Acquired 350GWh $215/MWh -$75m -$139m Length⁵ $86m Transmission/Storage -$71m Location losses⁶ -$85m Operating expenses -$272m Total $1m Total -$343m FY25 assumptions that deliver expected & normalised EBITDAF of $770m over a financial year EBITDAF guidance reconciliation to actual FY25 Hydrology & Asset availability optimise generation3 4 Totalx = Access to and price of fuel* drives financials & risk position Increased market channel price Normalised & Expected Lower renewables Other income Actual FY25 EBITDAF (underlying) Hydro generation below mean (-603GWh). Impact calculated at thermal SRMC Channel choices maximise long term value¹1 Net price² driven by best commercial practices2 Totalx = Trading delivers value to more than offset locational losses5 Digitalisation & continuous improvement optimise fixed costs6 x x x x x x x = = = = = = = 1. All volumes are at the Grid Exit Point (GXP). 2. Net price is equal to tariff less pass-through costs (network, meters and levies) /MWh. 3. Steam sales, retail gas gross margin, telco gross margin and other income. 4. Gas price of $8.2/GJ, carbon price of $80/unit and thermal portfolio heat rate (10GJ/MWh). 5. Length of 450GWh assumed. 6. Locational losses of 5.1% on spot purchases and settlement of CFDs. sold at a wholesale price of $190/MWh. Fixed costs LCE rebates ($11.5m) and AGS provision unwind partly offset by opex increase Normalised and expected EBITDAF assumptions FY25 results With reconciliation to actual performance x Increased long–term channel price Retail ($160/MWh) & Strategic fixed price sales ($85/MWh) prices higher than expectation (the latter due to NZAS demand response) Higher CFD price ($205/MWh) with tight market conditions and thermal-backed CFD sales Gas, carbon, acquired generation price Gas prices were materially higher in the period ($15/GJ) Demand response payments to NZAS included Volumes above expected; lower than expected location loses Net volume impact Risk management sales premiums and expected losses from distressed gas sales not realised Manawa transaction and integration costs EBITDAF pre Manawa-related costs * Fuel is natural gas and carbon costs. 136 38 102 17 17 18 4 15 770 792 774
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44 57 76 53 939 -258 -265 -291 -315 -346 -76 -85 -56 -74 -80 -230 -185 -94 -269 -326 1,069 48 FY21 1,023 FY22 FY23 1,269 FY24 1,476 50 FY25 Electricity sales margin Other gross margin Fixed operating costs Location losses Variable fuel costs 553 546 573 663 774 Operating earnings (EBITDAF) 108 106 115 127 136 3.61 1.33 FY21 3.69 1.39 FY22 3.73 1.42 FY23 3.80 1.22 FY24 3.69 1.73 FY25 4.94 5.08 5.14 5.02 5.42 Retail Strategic fixed-price 101 117 126 200 1.67 0.55 FY21 1.13 0.39 FY22 0.52 0.15 FY23 116 1.62 0.59 FY24 1.09 0.46 FY25 2.23 1.52 0.67 2.20 1.55 Thermal Acquired Electricity sales Variable fuel costs 1 1 1 1 1 3.70 3.11 FY21 3.94 3.28 FY22 3.92 3.19 FY23 3.63 3.39 FY24 3.30 4.54 FY25 6.81 7.22 7.10 7.02 7.84 Hydro Geothermal (i) Renewables (ii) Thermal and acquired 131 133 133 150 186 1.23 1.94 0.93 FY21 0.94 2.10 0.63 FY22 1.10 1.44 0.09 FY23 1.13 2.57 0.51 FY24 1.17 2.30 0.51 FY25 4.10 3.66 2.63 4.21 3.97 Commercial and Industrial CFDs Spot sales (i) Long-term channels (ii) Market channels Price ($/MWh) Volume (TWh) Price ($/MWh) Volume (TWh) Fuel cost ($/MWh) Volume (TWh) Fuel cost ($/MWh) Volume (TWh) Integrated portfolio performance Continuing operations ($m) 1 EBITDAF1 2 1 2 1 Refer to slide 50 for a definition and reconciliation of EBITDAF. All EBITDAF figures are underlying i.e. excluding the impacts of the ($113m) AGS onerous contract provision expense in FY23, a $12m net movement in the AGS provision in FY24, and a release of the AGS provision of $98m in FY25. 118 117 121 137 158 9.040 8.739 7.772 9.232 9.390 Price ($/MWh) Volume (TWh) Historic performance
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45 Greenhouse gas emissions Carbon reporting 1 Contact’s swaption with Genesis Energy ended 31 December 2022 and was not called during FY23. 2 All Science-based targets are on a calendar year basis. Indicator Unit Target FY21 FY22 FY23 FY24 FY25 Direct GHG emissions (Scope 1) tC02e 45% reduction of 2018 Scope 1 and 2 emissions by 2026 (Absolute emissions reduction target)2 1,044,744 786,842 526,621 947,491 740,468 - Stationary combustion tC02e 1,044,537 786,544 526,282 947,131 739,945 - Mobile combustion tC02e 178 297 307 332 409 - Fugitive emissions tC02e 29 1 32 28 114 Indirect GHG emissions (Scope 2) tC02e 1,303 1,399 1,957 975 1,183 Sub-total Scope 1 and 2 tC02e 647,443 1,046,047 788,241 528,579 948,466 741,651 Indirect GHG emissions (Scope 3) tC02e 259,118 555,035 394,784 273,673 265,034 369,583 - Category 1 – Purchased goods and services tC02e 30% reduction of 2018 Scope 3 GHG emissions from use of sold products by 20262 16,699 6,371 6,197 6,522 8,799 - Category 2 – Capital goods tC02e 41,726 57,876 88,266 79,185 87,203 - Category 3 – Fuel and energy1 tC02e 330,207 149,743 1,050 5,130 8,006 - Category 4 – Upstream distribution and transportation tC02e 27 444 108 254 205 - Category 5 – Waste tC02e 149 108 47 58 69 - Category 6 – Business travel tC02e 263 567 1,274 1,601 1,081 - Category 7 – Employee commuting tC02e 306 832 965 927 956 - Category 11 – Use of sold products tC02e 165,259 178,554 175,603 170,929 250,612 - Category 13 – Downstream leased assets tC02e 399 289 164 429 339 - Category 14 – Investments tC02e - - - - 12,313 Total Scope 1, 2 and 3 emissions tC02e 906,561 1,601,082 1,183,025 802,252 1,213,500 1,111,235
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46 Contact generation output sold to the national grid (GWh) Generation and sales position 3,256 3,333 3,114 3,283 3,185 3,388 4,543 4,231 3,752 3,698 3,940 3,919 3,628 3,297 1,421 1,360 1,592 1,046 1,620 1,088 FY19 FY20 FY21 FY22 439 FY23 FY24 FY25 Thermal generation Hydro generation Geothermal generation 8,908 8,445 8,404 8,269 7,543 8,636 8,928 Operational data Renewable % of own generation sold to grid 84% 84% 81% 88%87% 94% 81% Geothermal generation (GWh) FY25 geothermal generation was ~1.2TWh higher than FY24. Generation from the new Tauhara and Te Huka 3 plants (1.5TWh) was partially offset by statutory outages at Te Mihi, Wairakei and Ohaaki. 1,382 1,415 1,240 1,386 1,380 991 1,045 1,081 1,055 998 1,405 1,255 388 335 339 331 308 1,064 1,287 310 340 299 322 323 274 986186 198 155 189 176 316 300 203 277 210 FY19 FY20 FY21 FY22 FY23 127 FY24 229 FY25 3,257 3,333 3,114 3,283 3,185 3,388 4,543 Hydro generation (GWh) FY25 was marked by two periods of historically low inflows (July – August 2024 and January – April 2025). The result of these conditions meant total inflows for the year were 701GWh below FY24 volumes. 103 4,786 69 4,069 3,959 75 4,276 -59 3,904 -51 5,450 -101 3,681 -975 -1,606 -148 FY19 FY20 -275 FY21 -78 FY22 75 FY23 -230 FY24 -459 FY25 4,231 3,752 3,698 3,940 3,919 3,628 3,297 Inflows stored include uncontrolled storage lakes Inflows Inflows stored Spill Thermal generation (GWh) 1,013 871 1,126 673 164 1,395 692 207 291 234 179 148 223 378 195 195 213 190 125 78 583 FY19 379 FY20 1881 FY21 481 FY22 2 FY23 1 FY24 18 FY25 1,503 1,439 1,673 1,127 517 1,620 1,088 Although down significantly on FY24, thermal generation volumes were materially higher than mean expected volumes due to dry conditions in winter 2024 and Jan to April 2025. Te Huka Ohaaki Poihipi Wairakei Te Mihi Tauhara Te Huka 3 Whirinaki Te Rapa - direct Te Rapa - spot Stratford Peakers TCC
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47 Plant and fuel performance Geothermal fuel extracted at Wairakei vs consented (mT) Wairakei, Poihipi and Te Mihi conversion effectiveness (MWh per kT extracted) % of geothermal fluid extracted Wairakei mass extracted 20 40 60 80 100 0 99% 88 FY19 100% 90 FY20 98% 87 FY21 100% 89 98% 89 FY23 100% 91 FY24 95% 87 FY25FY22 -5% 31.4 31.1 30.5 31.0 30.4 29.2 29.7 FY19 FY20 FY21 FY22 FY23 FY24 FY25 +2% Geothermal fuel performance Taranaki combined cycle (TCC) Hydro Geothermal1 Stratford Peakers Plant availability Availability Factor calculation includes all station outages (Planned, Maintenance, Forced) but does not consider plant deratings. 1 Reduction in geothermal net capacity in FY23 was a result of decommissioning wells on the Wairakei steam field. Increases in FY24 and FY25 related to Tauhara and Te Huka 3 respectively. Whirinaki Wairakei total mass extracted, and extracted volumes as a % of consented mass take, were significantly down on FY24 as a result of a planned outage (25 days) at Te Mihi and an electrical outage at Wairakei A&B station. 2Statutory turnarounds occur after the first operating year of a new plant, again in operating year 3, and every four years thereafter. The table shows which plant have a major statutory turnaround in the next 3 calendar years. The GWh impact is an estimate based on understood scope at the time of publishing. Turnarounds in FY27 and FY28 are indicative. Upcoming geothermal statutory turnarounds (outages)2 Plant Impact (GWh) FY Frequency & type Tauhara 113 26 Y1 Stat Turnaround Te Huka 3 37 26 Y1 Stat Turnaround Wairakei 25 26 4y Stat turnaround Te Huka 1&2 25 27 4Y Stat Turnaround Wairakei 300 27 4y Stat turnaround + ext works Poihipi 31 28 4y Stat turnaround Te Mihi Stage 2 73 28 Y1 Stat Turnaround Tauhara 169 28 Y3 Stat Turnaround Te Huka 3 37 28 Y3 Stat Turnaround Net capacity (MW) Availability (%) Capacity factor (%) Electricity output (GWh) Pool revenue ($/MWh) ($m) FY21 377 89% 34% 1,126 193 217 FY22 377 84% 20% 673 180 121 FY23 377 85% 5% 164 107 18 FY24 377 82% 42% 1,395 184 257 FY25 377 89% 21% 692 330 229 Net capacity (MW) Availability (%) Capacity factor (%) Electricity output (GWh) Pool revenue ($/MWh) ($m) FY21 784 84% 54% 3,698 167 617 FY22 784 83% 57% 3,940 121 478 FY23 784 84% 57% 3,919 74 290 FY24 784 90% 53% 3,628 164 594 FY25 784 87% 48% 3,297 163 538 Net capacity (MW) Availability (%) Capacity factor (%) Electricity output (GWh) Pool revenue ($/MWh) ($m) FY21 425 89% 84% 3,114 175 546 FY22 425 97% 91% 3,283 140 458 FY23 410 94% 89% 3,185 80 254 FY24 586 94% 89% 3,388 177 601 FY25 635 90% 84% 4,543 186 845 Net capacity (MW) Availability (%) Capacity factor (%) Electricity output (GWh) Pool revenue ($/MWh) ($m) FY21 202 90% 13% 234 230 54 FY22 202 53% 10% 179 212 38 FY23 202 77% 8% 148 207 31 FY24 202 50% 12% 223 175 39 FY25 202 70% 22% 378 217 82 Net capacity (MW) Availability (%) Capacity factor (%) Electricity output (GWh) Pool revenue ($/MWh) ($m) FY21 158 94% 0% 18 410 7.5 FY22 158 95% 0% 4 597 2 FY23 158 82% 0% 2 491 1.2 FY24 158 97% 0% 1 687 1.1 FY25 158 92% 1% 18 661 12 Operational data
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48 Hawea storage (GWh) Gas storage (PJ) Closing storage Closing storage (current) Fuel storage movements Source: NZX Hydro data 166 260 113 252 188 141 85 263 324 190 322 265 242 232 330 174 -231 -334 -183 -326 -291 -286 -151 -278 1H22 2H22 1H23 2H23 1H24 2H24 1H25 2H25 Inflows Opening storage Releases 259 116 253 191 139 87 264 160 5.8 7.8 4.7 2.4 3.4 2.8 1.6 3.4 2.4 0.5 2.7 1.7 0.9 1.3 3.1 1.9 -3.5 -0.7 -0.7 -1.5 -2.5 -1.3 -2.0 -4.3 -0.4 1H22 2H22 1H23 2H23 1H24 2H24 1H25 2H25 Gas Injected Gas Extracted Opening Storage 7.8 4.7 2.4 3.4 2.8 1.6 3.4 3.3 Operational data 0 Transferred to long-term storage (PJ) 0 4 4 4 4 4 4 Long-term storage
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49 Contracted gas volumes (PJ) Uses of gas (PJ)Gas storage monthly injections and extractions (PJ) Contracted and stored gas Gas injected Gas extracted 5.4 3.6 7.0 7.0 7.0 7.0 7.0 7.0 6.2 5.6 2.9 3.6 3.0 2.6 2.2 2.8 2.8 2.8 4.4 3.8 0.0 CY24 CY251 CY262 CY27 CY28 CY29 CY30 CY31 CY32 15.3 10.3 10.6 10.0 9.6 9.2 9.8 9.8 9.0 Jul- 24 -0.51 0.25 Aug- 24 -1.24 0.01 Sep- 24 -0.96 0.02 Oct- 24 -0.24 Nov- 24 -0.09 0.180.12 -0.20 0.25 Jan- 25 -0.04 Dec- 24 0.81 Feb- 25 -0.13 0.48 Mar- 25 -0.03 0.17 Apr- 25 -0.60 0.28 -0.21 -0.68 0.07 0.77 Jun- 25 May- 25 9.8 6.6 9.8 6.3 8.8 6.4 9.1 6.4 -2.0 3.1 -2.0 -1.0 0.6 1.3 -1.8 -4.4 -6.5 -3.3 -2.7 -6.7 -6.4 -4.0 -5.2 -1.6 -1.3 -1.6 -1.1 -1.4 -1.1 -1.3 -1.0 -1.6 -1.9 -2.7 -1.4 -1.3 -0.2 -2.1 -0.5 1H22 2H22 1H23 2H23 1H24 2H24 1H25 0.2 2H25 Net extraction (injection) Generation Customer sales Wholesale sales Purchases Operational data 1 CY25 reflects actual volumes and forecasts for the second half of the year. 2 CY26-CY32 reflects the maximum volume of gas available under contracts. Forecasted volumes for these periods are not yet available. 3 Greymouth Gas volumes illustrated based on maximum gas available at Contact’s option up to October 2032. The contract also includes an option to extend for a further 3 years from October 2032. Short-term gas Greymouth Swap Maui Pohokura3
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5050 EBITDAF is Contact’s earnings before interest, tax, depreciation and amortisation, asset impairment and write-offs, and changes in fair value of financial instruments. EBITDAF is commonly used in the electricity industry so provides a comparable measure of Contact’s performance. Reconciliation of statutory profit back to EBITDAF: 12 months ended 30 June 2025 12 months ended 30 June 2024 Variance on prior year $m % Underlying1 Reported Underlying1 Against underlying Profit 261 331 230 31 13% Depreciation and amortisation 273 255 18 7% Change in fair value of financial instruments 35 (8) 43 na Net interest expense 100 35 65 186% Tax expense 104 132 101 3 3% Asset impairment / write-offs 1 50 (49) (98%) EBITDAF 774 872 663 111 17% Movements in depreciation and amortisation, net interest, tax expense and asset impairment / write- offs are explained on the right. Reconciliation between Profit and EBITDAF The movements between FY25 and FY24 underlying profit are as follows: • Depreciation and amortisation: Increased by $18m. Increase driven by Tauhara and Te Huka 3 (representing operational assets of ~$1.2b), partially offset by extension of the useful life of Wairakei assets and thermal assets now fully depreciated in FY24. • Net interest expense: Interest was up $65m on FY24 reflecting that debt related to Tauhara is no longer being capitalised. • Tax expense for the period increased by $3m due to the tax impact of higher operating earnings. Of note, FY24 tax expense was elevated by $6m relating to the removal of tax depreciation on buildings. • Asset impairment / write offs: Decreased 98%. In FY24, Contact recognised $50m write-offs relating to peaker engine damage, Tauhara assets (relating to the 2023 steam hammer event and failure of valves) and software assets (due to HRIS and CRM projects not proceeding as planned). Non-GAAP profit measure 1 All variances and commentary reflect movements in underlying performance. In FY24 Contact recognised a net movement in the AGS onerous contract provision of $12m within EBITDAF and $5m within profit – underlying excludes these impacts. In FY25, reported results include a release of the AGS onerous contract provision of $98m pre-tax ($71m after tax). Underlying performance excludes the impact of the provision release.
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51 S&P Net Debt / EBITDAF ratio FY21 FY22 FY23 FY24 FY25 Actuals from S&P ratings report Estimated Net Debt Carrying value of borrowings 856 1,099 1,556 1,913 2,449 Fair value adjustments (64) (55) (43) (41) (93) Restoration and environmental provisions net of tax 53 53 120 142 163 Hybrid bond credits1 - (113) (113) (113) (237) Accessible cash2 (41) (4) (89) (146) (514) S&P Adjusted Net Debt 804 980 1,431 1,763 1,768 EBITDAF Reported EBITDAF (underlying) 553 546 573 663 774 Realised gains/losses on market derivatives (1) (9) (27) (6) (13) Share based compensation 3 4 4 4 5 Transaction costs related to the Manawa acquisition 11 S&P Adjusted EBITDAF 555 541 551 661 777 Net debt/EBITDAF (x) 1.4 1.8 2.6 2.7 2.3 1 50% equity credit for capital bonds. 2 Cash less restricted cash held by Macquarie for ASX prudential. • These calculations have been provided as an illustration of the adjustments made by Contact’s ratings agency, S&P Global, when assessing Contact’s Net Debt/EBITDAF ratio. • Net Debt has been adjusted from the financial statements to include certain long-term liabilities where S&P considers these to have debt- like characteristics. • Adjusted EBITDAF reflects S&P’s view of core operating items (unrelated to investing and financing). S&P adjustments
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52 Reconciliation of change in fair value of financial instruments Change in fair value of financial instruments Realised / unrealised FY25 FY24 Variance Description (A) Net market making Realised (13) (3) (10) Realised gains or losses on the settlement of electricity derivatives entered into to meet Contact’s market making obligations - Market making Unrealised 2 4 (2) Mark-to-market of open electricity derivatives in future periods - NZAS long-term sale CFD (7) - (7) NPV of the changes to the forecast forward wholesale price path vs the wholesale path when the contracts were agreed- Kōwhai Park acquired PPA (13) - (13) - Other non-hedged movements (4) 7 (11) Mark-to-market of open electricity/interest rate derivatives in future periods (B) Unrealised movements in non-hedge effective electricity derivatives Unrealised (22) 11 (33) Total change in fair value of financial instruments as per segment note (A+B) Realised and unrealised (35) 8 (43) Commercial hedges recognised in EBITDAF that do not qualify for hedge accounting − Financial Transmission Rights (FTR) settlements and Exchange for Physical (ASX) Realised (5) - (5) Financial contracts that hedge portfolio sales that are settled in the period − Net settlement of NZAS contract in the period (134) - (134) Realised settlement (difference between the fixed contract and spot settlement) Change in fair value of financial instruments as per Income Statement (174) 8 (167) In the period, Contact entered into two long-term contracts for difference (CFD) that were not eligible for hedge accounting. These contracts relate to the sales of electricity to NZAS and the purchase of electricity from the under- development Kōwhai Park solar farm (expected online in Q2 CY2026). As a result, movements in expected wholesale prices when compared to forward wholesale prices when the contracts were entered into are recognised in change in fair value of financial instruments, increasing volatility of Net Profit After Tax. These non-cash movements, which relate to future periods, are recognised in the current period. The primary change to wholesale price expectations in the period was the listing of the 2028 ASX contract from October 2024, which was higher than Contact’s internally generated price path for the same period. Fair value of financial instrucments
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53 Historical financial information Unit FY21 FY22 FY23 FY24 FY25 Underlying2 Reported Underlying2 Reported Underlying2 Reported Revenue1 $m 2,573 2,387 2,118 2,867 3,306 Expenses1 $m 2,020 1,820 1,500 1,613 2,204 2,192 2,532 2,434 EBITDAF $m 553 546 573 460 663 675 774 872 Profit $m 187 182 211 127 230 235 261 331 Operating free cash flow $m 371 330 282 424 434 Operating free cash flow per share cps 50.2 42.4 36.0 53.9 54.4 Dividends declared cps 35 35 35 37 39 Total assets $m 5,028 5,166 5,808 6,208 6,813 Total liabilities $m 2,101 2,326 3,004 3,589 4,053 Total equity $m 2,927 2,840 2,804 2,619 2,760 Gearing ratio3 % 23 28 36 42 47 Historic performance 1 Revenue and expense figures align with the treatment of realised movements in financial instruments within the segment note of the financial statements. 2 In FY23 Contact recognised a net onerous contract provision expense for AGS of ($113m) within EBITDAF and ($84m) within profit. In FY24 Contact recognised a net movement in the AGS onerous contract provision of $12m within EBITDAF and $5m within profit. In FY25, the release of the AGS onerous contract provision increased reported EBITDAF by $98m and profit by $71m. Underlying performance excludes these impacts. 3 Gearing ratio is calculated as: Senior debt - including finance lease liabilities / (Senior debt - including finance lease liabilities + Equity). Note: From FY24 Contact no longer reports impairments and write-offs within EBITDAF. These are now reported separately to better reflect underlying performance. FY24 EBITDAF is stated excluding $50m of write-offs and impairments. Previous years have not been restated (FY22 includes a $1.5m peaker write-off).
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54 FY25 FY24 Year ended 30 June 2025 Year ended 30 June 2024 Volume GWAP Volume GWAP Note: this table has not been rounded and might not add GWh $/MWh $m GWh $/MWh $m Electricity sales to Retail segment 3,689 163 601 3,801 148 562 Electricity sales to C&I (netback) 1,566 133 208 1,456 129 188 CfDs – Tiwai support sales 920 892 PPAs 411 - CfDs - Long term sales 394 752 CfDs and ASX - Short term sales 1,903 1,820 Electricity sales – CFDs 3,629 157 569 3,465 118 407 Total contracted electricity sales 8,883 155 1,377 8,707 133 1,157 Steam sales 229 21 5 194 18 3 Other income 14 8 Net income on gas sales (12) 3 Net income on electricity related services 1 (0) Net other income 4 11 Total contracted revenue 9,112 152 1,386 8,901 132 1,171 Generation costs1 8,928 (44) (389) 8,635 (40) (349) Acquired generation cost 462 (264) (122) 585 (160) (93) Generation costs (including acquired generation) 9,390 (54) (511) 9,220 (48) (443) Spot electricity revenue 8,928 195 1,742 8,635 177 1,529 Settlement on acquired generation 462 252 116 585 195 114 Spot revenue and settlement on acquired generation (GWAP) 9,390 198 1,858 9,220 178 1,643 Spot electricity cost (5,255) (218) (1,143) (5,243) (193) (1,009) Settlement on CFDs sold (3,629) (191) (695) (3,465) (178) (616) Spot purchases and settlement on CFDs sold (LWAP) (8,883) (207) (1,838) (8,707) (187) (1,626) Trading, merchant revenue and losses 507 20 513 18 Wholesale EBITDAF underlying1 895 746 Onerous contract provision 98 12 Wholesale EBITDAF reported 994 758 Wholesale segment Segmental performance 1 In FY24 a net movement in the AGS onerous contract provision equated to $12m within generation costs and EBITDAF. In FY25, the release of the AGS onerous contract provision equated to $98m within generation costs and EBITDAF. Underlying performance excludes these impacts.
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55 Residential electricity unit FY22 FY23 FY24 FY25 Residential gas unit FY22 FY23 FY24 FY25 Average connections # 373,347 380,482 388,459 401,332 Average connections # 64,649 66,605 68,092 70,369 Sales volumes GWh 2,644 2,688 2,798 2,809 Sales volumes TJ 1,583 1,504 1,584 1,509 Average usage MWh per ICP 7.1 7.1 7.2 7.0 Average usage GJ per ICP 24.5 22.6 23.3 21.4 Tariff $/MWh 256.4 272.1 287.9 311.5 Tariff $/GJ 36.6 42.1 45.1 52.9 Network, meters and levies $/MWh -119.5 -122.7 -128.0 -142.2 Network, meters and levies $/GJ -18.9 -22.9 -24.5 -29.0 Energy costs1 $/MWh -115.0 -138.6 -158.8 -174.5 Energy costs $/GJ -11.8 -10.1 -9.8 -11.0 Gross margin $/MWh 21.9 10.8 1.1 -5.1 Carbon costs $/GJ -2.1 -4.2 -3.1 -4.4 Gross margin $ per ICP 155 77 8 -36 Gross margin $/GJ 3.8 4.9 7.7 8.5 Gross margin $m 58 29 3 -14 Gross margin $ per ICP 92 112 181 182 Gross margin $m 6 7 12 13 SME electricity unit FY22 FY23 FY24 FY25 SME gas unit FY22 FY23 FY24 FY25 Average connections # 48,459 46,962 44,113 41,654 Average connections # 3,889 3,519 2,972 2,662 Sales volumes GWh 798 794 754 651 Sales volumes TJ 1,224 1,063 794 607 Average usage MWh per ICP 16.5 16.9 17.1 15.6 Average usage GJ per ICP 315 302 267 228 Tariff $/MWh 239.7 259.3 282.2 313.4 Tariff $/GJ 19.8 25.2 31.0 38.5 Network, meters and levies $/MWh -112.9 -117.0 -118.3 -132.9 Network, meters and levies $/GJ -8.3 -9.5 -11.6 -13.9 Energy costs1 $/MWh -113.7 -138.6 -157.3 -174.5 Energy costs $/GJ -11.8 -10.1 -9.8 -11.0 Gross margin $/MWh 13.0 3.6 6.6 5.9 Carbon costs $/GJ -2.1 -4.2 -3.1 -4.4 Gross margin $ per ICP 215 62 112 93 Gross margin $/GJ -2.4 1.4 6.5 9.2 Gross margin $m 10 3 5 4 Gross margin $ per ICP -769 412 1,750 2,103 Gross margin $m -3 1 5 6 Telco unit FY22 FY23 FY24 FY25 Retail segment EBITDAF FY22 FY23 FY24 FY25 Average connections # 62,388 79,057 95,168 116,709 Electricity Gross margin $m 68 32 8 -11 Tariff $/cust/mth 70.1 69.6 71.8 72.1 Gas Gross Margin $m 3 9 17 18 Network, provisioning, modems $/cust/mth -60.5 -63.5 -63.4 -62.8 Telco Margin $m 7 6 10 13 Gross margin $/cust/mth 9.6 6.2 8.4 9.3 Total Gross Margin $m 79 47 35 21 Gross margin $m 7 6 10 13 Other income $m 7 9 7 4 Other operating costs $m -68 -69 -74 -74 Retail segment EBITDAF $m 17 -14 -32 -49 Corporate allocation (50%) $m -14 -22 -25 -36 Retail EBITDAF $m 3 -36 -57 -85 EBITDAF margins (% of revenue) % 0.3% -3.3% -4.8% -6.6% Retail segment Segmental performance 1 Energy costs reflect electricity purchased from solar customers: $1.2m in FY24 and $2.7m in FY25.