Slides
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2026 full year results presentation Twelve months ended 30 June 2026 10 August 2026 contact
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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. Contact recommends that you read this presentation in conjunction with both its market announcements and the materials attached to those announcements, and in particular the market announcements and materials it released on the date of this presentation. These are available on the NZX website (at www.nzx.com), ASX website (at www.asx.com.au) and on Contact's website (www.contact.co.nz). 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 Agenda FY26 Highlights Mike Fuge Chief Executive Officer Financial results & outlook Strategy update Matt Forbes Chief Financial Officer Supporting materials Mike Fuge Chief Executive Officer Slides 4 to 9 Slides 10 to 22 Slides 23 to 29 Slides 31 to 51
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4 FY26 highlights Total shareholder return FY26 Continued representation within DJ BIC Asia Pacific and MSCI indices Delivering for shareholders Manawa acquisition completed 100% of the $28M identified cost synergies secured (run-rate basis) Manawa hydro and PPAs increased renewable output by 2.4TWh in FY26 Generation at new Te Huka 3 geothermal plant 0.4TWh in FY26 Contracted 50MW Huntly Firming Option for 10 years to manage dry year risk, supporting security of supply Delivering portfolio change Delivering renewable energy growth Delivering financial performance Delivering for customers Delivering for the market +9% +37% Renewable output YoY renewable in FY263 98% Financial close reached on Glorit solar 150MWac / 287GWh p.a. Kōwhai Park solar in commissioning 150MWac / 275GWh p.a. Glenbrook-Ohurua 100MW battery online and 200MW battery under construction +31% +62% NPAT $423M up $162M YoY EBITDAF1 $1,011M up $237M YoY 40cps Total dividend Average ROIC2 5.9% up 100bps YoY +100bps Commenced electricity supply to NZ Steel’s new EAF4 AoG5 contract providing 2PJ of gas to core community assets 165k households choosing discounted or free off-peak energy6 Contact Good Initiative $5M supporting customers and communities 1. Refer to slide 46 for a definition and reconciliation between statutory profit and the non-GAAP profit measure earnings before net interest expense, tax, depreciation, amortisation, change in fair value of financial instruments (EBITDAF). FY25 EBITDAF is an underlying figure that excludes release of the AGS onerous contract provision that increased reported EBITDAF by $98M and profit by $71M. | 2 ROIC average is calculated as NOPAT (4-year average) / Average IC (4-year average). Refer to slide 19 for the operating free cash flow reconciliation and for the basis of calculation of return on invested capital. | 3. Renewable generation includes wind and geothermal PPA purchases but excludes short-term acquired generation purchases e.g. fuel replacement via ASX which will reflect the renewable mix of the market | 4. Electric Arc Furnace (EAF). | 5. All of Government (AOG). | 6. As at 30 June 2026.
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5 New Zealand electricity market was 93% renewable in FY26 Inflows & hydro: Hydro inflows 118% of post market mean.1 Total market renewable percentage was 93% 2, the highest rate achieved since the market was introduced. Network and transmission pressures continue: Lines cost increases from 1 April 2025.8 Demand returns: Demand was robust, up ~3% on FY25, ~1% normalised for NZAS6 demand response.7 Gas production continues to decline: 2P Gas production forecast for 2027 is down 24% compared to the same forecast last year.9 High inflows, energy storage and record renewable generation have led to subdued pricing 1. Source: NZX Hydro. | 2. Source: EMI. | 3. Source: Electricity Authority. Generation output by plant. | 4. Ahuroa Gas Storage Facility (AGS). | 5. Source: ASX. Change in ASX Settlement prices at Otahuhu for Q3 2026 from 31 December 2025 to 30 June 2026. | 6. New Zealand Aluminium Smelters Ltd. On 1 July 2024, responding to dry market conditions, Meridian called on its demand response contract with NZAS resulting in operations being turned down and demand for electricity being reduced temporarily in 1H25. | 7. Source: EMI and Contact. | 8. Source: Commerce Commission. 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). | 9. Source: MBIE electricity & gas data. ASX futures soften: Winter 2026 pricing fell by more than 60% over 2H FY26, reflecting high energy storage.5 Longer-term futures pricing fell 27% over 2H FY26,2 with the market moving into supply / demand balance on the back of renewable generation investment. Energy storage: FY26 ended with hydro lakes at 135% of mean3, gas storage (AGS4) close to full, and the Genesis coal stockpile at 1,189kt (up 70% on prior year), all contributing to low fuelling risk for winter 2026. Market update
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6 ▪ NZAS now operating on long- term supply contracts coupled with demand response. ▪ 1TWh of committed dairy electrification projects to be supported by summer- weighted generation. ▪ NZ Steel’s Electric Arc Furnace backed by shaped supply contract. ▪ Market and regulatory settings have evolved alongside the energy transition. o Non-discrimination obligations and super-peak market making have been implemented. o Enhanced EA enforcement and regulatory powers have been introduced. ▪ NZAS demand response mechanisms in place for dry year support. ▪ Huntly Firming Options signed to support dry year capacity. ▪ Strategic coal reserve and stored gas and hydro. ▪ Fast Track consenting regime now operating. ▪ New renewable generation added 4TWh over the last five years (BCG).1 ▪ Electricity market reached 93% renewable in FY26. ▪ Industry-wide focus on energy wellbeing consumer care and reducing barriers to access. ▪ Disconnections viewed as last resort. ▪ No disconnection or reconnection fees (Contact). ▪ In FY26 Contact Good Initiative provided ~$5M of customer and community support. The market has adapted for the energy transition Investing at pace in renewable energy Managing fuel security and dry year risk Enhancing market settings Supporting energy wellbeing Sector investment, customer innovation and market settings have all advanced as New Zealand has progressed through the energy transition ▪ RMA Reform: Planning and Environment Bills expected to pass by end of year. ▪ ~3TWh of generation either committed or under construction and expected to come online by 2027.2 ▪ Consultation to conclude in 2026 on MBIE’s proposed Winter Reliability Obligation framework. ▪ Potential to extend HFO for further dry year support. ▪ Potential for right-sized LNG import terminal to enhance fuel diversity. ▪ Potential for diesel storage as an additional strategic reserve. ▪ Contact advocating for a market-wide obligation to connect to further lift energy wellbeing outcomes. ▪ $7.5M committed through Contact Good Initiative in FY27 to support customers and communities. DeliveredLooking ahead Innovating for industrial and commercial customers ▪ Potential reopening of NZAS Line 4 potline at Tiwai Point. ▪ Continued dairy electrification, aligned to summer load. ▪ Estimated New Zealand data centre capacity of up to ~725MW by 2035 (Invest NZ).3 1. Boston Consulting Group. Energy to Grow: Securing New Zealand’s Future (2025). | 2. Company announcements and Contact’s analysis. | 3. Invest New Zealand, Data and AI infrastructure Report (2026). Data based on base case scenario. Market update
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7 Renewable investment programme continues Glenbrook-Ohurua Battery 2 200MW / 400MWh Target online Q1 CY28 Target IRR >10% at FID3 Te Mihi Stage 2 Geothermal 101MW / ~840GWh p.a. (~200GWh net uplift)4 Target online Q3 CY27 Target IRR ~10% at FID3 Glorit Solar 150MWac / 287GWh p.a. Target online Q4 CY28 Target IRR >12% at FID2 Te Mihi Stage 2 • Construction underway. Earthworks began March 2026. • Battery packs under construction with lithium price locked in second half 2025. • Steamfield separator, heat exchangers and turbines for the first unit installed. Cooling tower near complete. • Delays being incurred in equipment delivery, in part due to global shipping constraints. • Target online remains Q3 CY27. • Financial close reached in June 2026. • Early works underway. • Notice to proceed issued to EPC contractor. 1. Total construction cost over the life of the projects including joint venture and project financing (solar). | 2.Target Contact IRR includes joint venture returns and margin on acquired generation. Return on acquired generation will ultimately depend on sales channel and market conditions. | 3. Representing target ungeared project IRRs. | 4. Indicative average uplift from new generation accounting for the planned partial closure of Wairakei geothermal station. Glenbrook-Ohurua Battery 2 Glorit Auckland Wellington Strategy delivery Current projects under construction represent ~$1.3b of investment1, ~0.5TWh of net new generation Under construction: Kōwhai Park In commissioning Glenbrook-Ohurua Battery 1 Online Mar 2026 Te Huka 3 Online Dec 2024 Tauhara Online May 2024 Recent projects – Continuous build programme since 2021: +275GWh p.a.+100MW / 200MWh+430GWh p.a.+1,450GWh p.a.
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8 Benefits from Manawa integration realised Strategy delivery An $84M uplift has been secured in FY27, excluding benefits from generation normalisation, 35% higher than the long-run benefit indicated at deal announcement 22 28 FY26 FY27 Opex synergies delivered, $M (in-year) Integration benefits secured, FY271 100% of identified cost synergies have been secured at $28M (FY26 exit run-rate basis) $23M to $28M targeted at deal announcement EBITDAF uplift $M Change $/MWhGWh 2652500Mercury volume resold to C&I and CFD channels2 4450869Mercury volume shifted to ASX-linked pricing3 (14)(22)640Mercury wind PPA repricing 56Net repricing benefit 28Cost synergies achieved (FY26 exit run-rate) 84Total uplift Integration benefits of $84M secured for FY27 (excluding generation normalisation)1 +35% on long-run expected benefits indicated at deal announcement Legacy Manawa development options Huriwaka (wind), Kaihiku (wind)4 and Argyle (solar) are being actively advanced. Together they represent potential to contribute 2.1TWh p.a. of output.5 Development pipeline advanced 1. Benefits have been illustrated excluding generation normalisation as this can be expected to fluctuate year on year with hydrology and wind conditions. | 2. Indicative price change reflects a mix of FY27 channel pricing of $168/MWh for C&I (net price) and $155/MWh for CFD, which are 95% and 98% sold respectively. Compared to fixed price in FY26. Includes portfolio benefit of $16M given Contact’s ability to sell 300GWh of Manawa generation that would previously be held as a risk buffer.| 3. Repriced with reference to ASX. As at publication, ~97% of FY27 repricing is confirmed. Compared to fixed price in FY26. | 4. Kaihiku is a 50:50 JV with Pioneer Energy. | 5. All development options remain subject to FID. Pending appropriate market conditions and projects meeting returns thresholds.
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9 Contact has delivered on the FY26 plan FY26 operational plan ▪ Multi-product customers >156k (up from 149k). Decarbonise our portfolio Create outstanding customer experiences Strategic theme Impressive delivery of the strategic targets outlined at the start of the year Manawa integration In-year benefits target: ▪ Targeting net price up by ~2%. Exit run-rate benefits target: 1. Cumulative measure, shown on a total contracted basis. | 2. Total retail operating costs (direct and indirect) / average connections. Includes customer acquisition costs. This is $113 per connection based on closing connections. | 3. This is a through-the-cycle measure. Actual result will be impacted by hydrology, fuel and other market conditions. | 4. Based on the sale of 300GWh risk management buffer at a blend of FY27 CFD and C&I pricing. Refer to slide 8 for detail. ▪ Cost to serve <$116/connection.2 FY26 achieved ▪ Opex reduction $10M to $20M. ▪ Portfolio benefits $5M.3 ▪ Opex reduction $22M to $25M. ▪ Portfolio benefits $10M to $20M.3 Multi-product customers 165k. Net price target exceeded. Cost to serve $117 per connection.2 Opex reduction of $22M achieved in-year. Portfolio benefits >$5M achieved in-year. Portfolio benefits of $16M secured for FY27.4 Exit run-rate achieved. Opex reduction exit run-rate of $28M achieved. ▪ Close TCC gas generation plant late CY25. ▪ Sustained New Zealand leadership position in the Asia Pacific DJSI. ▪ Scope 1 & 2 emissions <650ktCO2e. TCC closed, at end-of-life, after 30 years in service. FY26 Scope 1 & 2 CO2e of 319kt (gross). Contact maintained in the Dow Jones Best-in-Class Asia Pacific Index (formerly Asia Pacific DJSI). ▪ Achieve FID for CO2. Grow Demand ▪ New demand facilitated since FY21 to reach >250MW.1 ▪ At least 50% of new demand contracted in-year structured with favourable shape (considering load and generation). The CO2 project is under development with active technology trials underway. New demand facilitated since FY21 is 258MW of which 157MW is currently operational. Additional 101MW expected online in FY27. New in-year demand contracted in FY26 of ~28MW of which 26MW is summer-weighted. ▪ Glenbrook-Ohurua Battery 1 online Q1 CY26. Grow renewable development Subject to market conditions and obtaining consents, achieve FID on: ▪ Consents lodged on at least 2 renewable development projects. ▪ Kōwhai Park solar online Q2 CY26. ▪ Te Mihi Stage 2 geothermal on track for online Q3 CY27. ▪ Solar (e.g. Glorit, Argyle); and/or ▪ Glenbrook-Ohurua Battery 2 (200MW). Glenbrook-Ohurua Battery 1 online in March 2026. Te Mihi Stage 2 on track to be online for Q3 CY27. Kōwhai Park in commissioning, expected online Q3 CY26. Lodged for Glenbrook-Ohurua Battery 2 and Stratford hybrid-solar. FID achieved (Glorit). Reached financial close in June 2026. FID achieved. Construction underway. Strategy delivery
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10 Financial results and outlook
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11 Twelve months ended 30 June 2025 (FY25)1 Twelve months ended 30 June 2026 (FY26)1 Against underlying2Reported 3% from $3,306M↓$3,206MRevenue3 31% from $774M↑$1,011MEBITDAF4 900bps from 23%↑32%EBITDAF margin 62% from $261M↑$423MProfit 27% from 32.7c↑41.5cProfit per share 49% from $434M↑$648M Operating free cash flow5 18% from 54.4c↑64.0cOperating free cash flow per share5 100bps from 4.9%↑5.9%Average ROIC 18% from $355M↑$419MDividend declared 3% from 39.0c↑40.0cDividend declared per share 32% from $110M↑$145M Stay-in-business (SIB) capital expenditure (cash) 3% from $363M↑$375MGrowth capital expenditure (cash)6 Summary of key financial performance measures Strong result with $1,011M EBITDAF reflecting investments in renewable generation 1. Includes Manawa from 11 July 2025. Prior period does not include Manawa. | 2. In FY25, the release of the AGS onerous contract provision increased reported EBITDAF by $98M and profit by $71M. These impacts have been removed from underlying performance. All variances and commentary reflect year-on-year changes in underlying performance. | 3. Revenue figures align with the treatment of realised movements in financial instruments within the segment note of the financial statements.| 4. FY26 EBITDAF was $1,037M excluding Manawa transaction and integration costs of $26M. Refer to slide 46 for a definition and reconciliation of profit to EBITDAF. | 5. Refer to slide 19 for a reconciliation of operating free cash flow. | 6. Includes capitalised interest. Delivering on the benefits of the Manawa acquisition with 100% of cost synergies delivered: $22M in-year ($28M run-rate basis) TCC closure and reduction in gas generation (down 79% on FY25) Increasing sales to major users in the long-term inflation- protected, strategic fixed price sales channel Manawa acquisition added 2.4TWh of additional volume in-year from hydro generation and PPA contracts Glenbrook-Ohurua Battery 1 online, shifting 11GWh of volume in the first 3 months of operating Key themes from the results Record performance reflecting greater scale from renewable development and the Manawa acquisition
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12 Profit, $M EBITDAF up $237M (31%) on FY25 (underlying), reflecting the Manawa acquisition and increase in renewable generation Profit of $423M for FY26 EBITDAF, $M Prior period gas and acquired generation prices were elevated by short-term Methanex gas, NZAS demand response and fuel scarcity conditions. Combination of higher channel pricing and a mix shift between strategic and retail channels. Renewables up with the addition of Manawa generation, normalisation of hydro output, and a full year of Te Huka 3. This now includes Manawa irrigation income. Prior period included losses on sale of excess Methanex gas. 431 FY26 results FY25 EBITDAF1 1. Renewables 2. Net volume 2 Higher contracted sales volumes underpinned by higher generation and Manawa contracted sales acquired as part of the transaction. 6 3. Long Term channel pricing 5. Gas, carbon and acquired generation price 6.Other income 122 88 40 51 103 98 774 -21 -32 -8 -106 872 225 -114 1,011 4. Market channel pricing Hydro conditions led to a normalisation of CFD prices. These were elevated in FY25 as risk management contracts reflected challenging market conditions. 5 7 7.Fixed operating costs Manawa fixed costs, inflation impacts, non- recurrence of AGS provision unwind benefit and transaction and integration costs ($8M higher than prior period). Partly offset by in-year cost synergies and productivity benefits. FY25 profit1 Net interest costs EBITDAF Depreciation & Amortisation TaxChange in FV of financial instruments FY26 profitAsset impairment / write-offs FY26 EBITDAF AGS onerous contract release (pre-tax) Acquired Manawa hydro (measured at GWAP) Manawa transaction & integration costs 261 423 237 39 71 -21 -40 17 -8 -62 331 56 AGS onerous contract release (after-tax) Realised change in FV of financial instruments Unrealised change in FV of financial instruments 1. In FY25, the release of the AGS onerous contract provision increased reported EBITDAF by $98M and profit by $71M. These impacts have been removed from underlying performance. All variances and commentary reflect year-on-year changes in underlying performance. 32.7 41.5Profit per share, cps
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13 Wholesale EBITDAF, $M1 Retail EBITDAF, $M Corporate / unallocated costs, $M Operating performance by segment EBITDAF up by $237M Refer to slides 14 - 16 Refer to slide 17 -49 -41 FY25 0 Electricity Volumes 125 130 Electricity Prices 17 Other products2 4 Opex FY26 +7 Electricity gross margin (-$6M) Electricity and network cost inflation Price recovery 2. Other products includes retail gas and telco gross margins. FY26 results: Segmental performance 1. Simply and Western included within Wholesale EBITDAF. EBITDAF is shown excluding a $98M provision release in FY25 (underlying EBITDAF). 3. Increase net of in-year synergies. | 4. Stats NZ CPI increase over the 12 months to June 2026 plus wage inflation. 55 18 FY25 6 Transaction & Integration Cost Increase 9 Acquired Manawa corporate costs 5 Inflation & Non Recurring 69 24 FY26 -73 -93 -20 4 Manawa transaction & integration 895 1,145 281 FY25 15 Generation costs (including acquired generation) Total contracted revenue 15 Trading, merchant revenue and losses FY26 +250 3
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14 Electricity generated or acquired, GWh Generation volume rises significantly, reflecting greater scale and portfolio diversity FY25 FY26 Electricity generated or acquired costs, $M Generation costs FY26 results: Wholesale business Gas and diesel Acquired Thermal Renewable Gas storage1 Carbon costs Electricity and gas transmission and levies Other operating costs Generation volumes • Contribution from Manawa hydro assets and a normalisation of hydro output led to a 53% increase (1,735 GWh) in hydro generation. Despite high inflows, generation was ~718GWh below Contact’s mean expectation for FY26 (5,750GWh) owing to a period of spill in summer 2025. • Geothermal volumes were up 371GWh on FY25 (8%) supported by a full period of Te Huka 3. This was partially offset by statutory outages at Tauhara, Te Huka 3 and Wairakei. • Thermal generation supported Winter 2025, however, strong hydro inflows and new renewables brought online in the last 18 months reduced the need for thermal with generation falling 859GWh, 79% year on year. • PPA purchases of 827GWh in FY26 reflected wind and geothermal PPAs acquired with Manawa. • Market acquired generation was purchased to cover geothermal statutory outages and when spot prices were advantageous. Total volume was up 223GWh on FY25. Costs were $84.4/MWh lower than FY25 despite HFO premiums now being included. Costs • Renewable generation costs were up $69M (46%) on FY25, including $66M from hydro ($53M driven by operating new stations). • Thermal generation costs were down $139M (-60%) on a lower cost of gas per unit (FY25: $15.4/GJ, FY26: $13.9/GJ). 4,543 4,914 3,297 5,032 1,088 462 685 827 FY25 229 FY26 PPA purchases Market acquired Thermal Hydro Geothermal 9,390 11,687 134 197 149 37 218 41 233 143 94 27 122 61 203 26 31 122 80 123 8 Generation type 14 Cost type 11 Generation type Cost type 511 511 526 526 +15 88%Renewable % of own generation 98% $54.40/MWh $44.96/MWh 1. In FY25, gas storage costs included a $14.6 million provision unwind released throughout the year. Development Market acquired PPAs
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15 601 657 169 307 471 312 146 361 45 -9 FY25 375 -12 FY26 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 1,386 1,666 +281 3,675GWh $178.7/MWh Contracted revenue, $M Diversified mix of long-term and ASX-linked sales channels 2,008GWh $155.4/MWh -14GWh +$15.8/MWh -289GWh -$49.5/MWh Contracted wholesale revenue increased in aggregate as Contact made additional sales backed by the addition of the Manawa assets and PPAs. • Sales to the retail segment were down 14GWh as lower average customer usage offset growth in customer connections during FY26. Pricing on sales to retail increased by $15.8/MWh to $178.7/MWh, reflecting higher wholesale electricity prices over recent years. • C&I channel sales were up 694GWh driven by growth in customer contract volumes, including the addition of contracts acquired through the Manawa transaction. Net Price increased $20.6/MWh reflecting contract repricing and the inclusion of higher-priced contracted volumes acquired through Manawa. • CFD sales volumes were down 289GWh as a greater proportion of contracted sales were directed into strategic long-term channels and C&I contracts. Hydro conditions led to a normalisation of CFD pricing, down $49.5/MWh to $155.4/MWh. Prices were elevated in FY25 as risk management contracts reflected challenging market conditions. • Strategic fixed price volumes were up 2,180GWh driven by the acquisition of the long-term Mercury CFD from Manawa, a full year of Tauhara-linked CFDs, increased sales to NZAS and the commencement of the NZ Steel contract. Prices were up by $7.8/MWh as new long-term agreements better reflect Contact's long-run view of electricity pricing. • Other income was $33M higher due to the inclusion of irrigation net income from Manawa (+$11M), non recurrence of gas sold at a loss in FY25 (+$14M) and Peaker GT22 insurance proceeds ($12M). Wholesale contracted revenue 1,864GWh $164.7/MWh +694GWh +$20.6/MWh FY26 results: Wholesale business 3,907GWh $92.5/MWh +2,180GWh +$7.8/MWh Year-on-year changes to volume and price FY26 volumes and price
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16 Trading EBITDAF, $M Long / short position, GWh 9.0% ($7.4/MWh) 1.5% ($1.2/MWh) In FY26 high hydro inflows coupled with strong wind conditions in 1H26 and the addition of new renewable generation brought online in the last 12 months led to subdued spot prices. FY26 conditions were shaped by: • Elevated but highly concentrated hydro inflows led to spill, reducing hydro output. • High wind conditions in 1H26 compounding the increase in supply and adding to spill conditions. • Subdued wholesale spot prices throughout the year. • A shift away from merchant exposure, to long- term contracts. Contact’s LWAP/GWAP spread fell to ~1% on the back of revised portfolio dynamics following the Manawa integration and geothermal build, very low spot prices, and improved FTR1 outcomes. This resulted in a very low absolute LWAP / GWAP spread, significantly reducing Contact's LWAP / GWAP losses. 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 $80.4MWh Spot purchases and sell CFD settlement Spot sales and buy CFD settlement Merchant generation 100 19 -80 -14 FY25 FY26 20 5 507 8,883 -8,883 FY25 11,464 -11,464 FY26 507 234 234 FY26 results: Wholesale business LWAP/GWAP losses $197.9MWh Trading EBITDAF reflected reduced merchant exposure and subdued wholesale spot prices 1. Financial Transmission Rights (FTRs).
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17 1 Retail business performance EBITDAF, $M Retail EBITDAF up $7M despite higher energy and lines costs, supported by Gas and Telco margin growth and 50k connection growth VarianceFY26FY25 Revenue & Tariff, $M Tariff$MTariff$M$M +$38/MWh128$350/MWh1,2071,079Electricity revenue -$2/GJ95$47/GJ198103Gas revenue -$1/connection16$71/cn117101Telco revenue -347Other income 2371,5271,290Total revenue $134$129Cost to serve/customer1 666k633kAverage connections $117$116Opex per connection 1. Reflects total operating costs (direct and indirect) less customer acquisition costs / closing customers. | 2. Retail connections and customers only, excludes Simply Energy.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. | 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). Costs are increasing annually. 13 17 18 33 -11 -16 -74 -78 4 FY25 3 FY26 Other Gas GM Electricity GM Telco GM Other operating expenses -49 -41 FY26 results: Retail business FY26 Gas642 692 FY25 445 148 465 437415 124 79 Customers Telco Electricity 73 Closing customers & connections2, ‘000s $181/MWh$164/MWhEnergy cost3 $153/MWh$132/MWh Networks, meters and levies3 Retail EBITDAF increased by $7M on FY25 largely due to strong growth in Gas and Telco margins, partially offset by high wholesale prices and rising distribution costs: • +$130M increase in electricity input costs, which were not fully passed through to customers. • The average Retail electricity tariff increased by +12% reflecting widespread retail price rises to partially offset higher wholesale costs and full recovery of lines cost increases. • Around 90% of customers received a price increase in the last 12 months. Cost pressures on the lines component of the tariff are expected to remain as the increased costs of transmission and distribution infrastructure continue to be incurred.4 Moderating wholesale prices are expected to lower the electricity component over time. Connections grew strongly throughout FY26, particularly through Telco and Time of Use (ToU) electricity Good plans, with a focus on multi-product customers. • Total connections +50k on FY25 with Telco up 24k and Energy up 26k. • Multi-product customers up 10% on FY25, driven by strong Telco product attachment alongside ToU Good plans growth. Opex – increased by $1/connection, largely driven by wage inflation, partially offset by increased connections, and productivity improvements through continued growth in digitised interactions.
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18 Other operating cost movement FY26, $M FY26 movement commentary Manawa acquired opex • $93M Manawa related opex from FY25 Manawa financial statements ($117M) excluding one-off bad debt for Prime Energy (-$7M), transaction costs (-$7M) and transmission costs which Contact includes in gross margin (-$10M). Base movement and headwinds • $9M general inflation of 3.1% impacting operating costs. These have been seen across all cost categories including labour cost. • $2M increase in bad debts over Retail mass market and C&I segment with Kiwi Crunch liquidation. Synergies & productivity delivered • $22M from Manawa related synergy delivered within FY26. • $2M related to continued efficiency from Retail cost to serve. Growth • $2M incremental costs with Te Huka 3 online vs prior year. • $2M incremental investment related to retail connection growth. Manawa transaction and integration related costs • $8M additional transaction and integration related costs incurred with transaction related costs up $3M and integration costs up $5M. Operating costs increase on inflation and growth FY26 results: Operating costs 93 24 26 276 FY25 Manawa acquired opex 92 General inflation and headwinds Synergies and productivity 4 Growth FY26 underlying Manawa transaction and integration costs FY26 reported 11 361 387 FY26 Manawa transaction and integration costs FY25 Manawa transaction and integration costs General inflation (3.1%) Headwind & non-recurring costs 11 16 FY26 BAU Inflation 4 Growth Synergies & productivity FY27 BAU 361 360 Expected other operating cost movement FY271, BAU $M 18 1. BAU opex will exclude SaaS implementation and Manawa integration costs.
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19 • Higher EBITDAF on FY25 (underlying), as detailed on slide 12. • Working capital change was a positive $20M impact to OpFCF (vs. negative $35M in FY25), mainly due to a reduction in carbon unit inventory reflecting changes in thermal generation. • Tax paid was $13M higher, reflecting the addition of provisional tax payments for Manawa and KCE groups, offset by a lower FY25 final tax payment that is paid during FY26. • Interest paid, net of capitalised interest, rose by $45M. Linked to increased borrowing in support of the Manawa acquisition. • FY26 stay-in-business (SIB) capital expenditure includes previous accelerated programme ($14M), geothermal and hydro enhancement projects and integration ($12M), Wairakei extension ($21M) and risk- rated and improvement projects ($98M). Comparison against FY25 12 months ended 30 June 2026 12 months ended 30 June 2025 $237M↑$1,011M$774MEBITDAF $55M↓$20M($35M)Working capital changes ($13M)↑($119M)($106M)Tax paid ($45M)↑($122M)($77M)Interest paid, net of interest capitalised ($35M)↑($145M)($110M)SIB capital expenditure $15M↓$3M($12M)Non-cash items included in EBITDAF $213M↑$648M$434MOperating free cash flow 9.6 c↑64.0 c54.4 cOperating free cash flow per share up 900bps↑64%55%Cash conversion (OpFCF / EBITDAF) Return on invested capital (ROIC) Cash conversion higher driven by strong EBITDAF growth and reduced value of fuel inventory Cash flow and capital expenditure Sources and uses of cash, $M FY26 results: Cash flow 200 174 96 251NOPAT, $M 1. 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 movement in the AGS provision for FY23, FY24 and FY25. | 2. ROIC average is calculated as NOPAT (4-year average) / Average IC (4-year average). | 3. ROIC (FY) is calculated as Annual NOPAT (FY) / Average IC (FY). 648 387 575 375 121 358 253 184 47 Sources 3 Uses 1,395 1,395 Cash Accumulated Net debt drawdown OpFCF Dividend re-invested (DRP) Sale of asset Strategic investments / acquisitions Growth investment Dividends paid Realised losses on market derivatives Financing costs 0 1 2 3 4 5 6 7 8 9 3.7% 3.7% 3.3% 3.7% 4.9% 5.9% ROIC (average)2 ROIC (FY)3 475 Net operating profit after taxes (NOPAT) / Invested capital (IC)1 Average IC, $M 4,482 4,518 4,874 5,349 5,670 7,412 FY21 FY22 FY23 FY24 FY25 FY26 Equity raise 557
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20 Approach and FY26 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 FY26 year-end, the point estimate of net debt to EBITDAF was 2.1x. • During FY26, Contact issued an inaugural €500m European Medium Term Note (EMTN). This debt was certified against the Green Bond Principles under Contact’s Sustainable Finance framework and supported the funding of the Manawa acquisition. • Contact repaid the $14M of remaining NEXI export credit facility and $88M US Private Placement debt (USPP) early in April and May 2026 respectively and closed out the related cross currency swaps. Looking ahead • The first reset date of the Capital Bond issued in 2021 is approaching in November 2026. Contact intends to redeem the bonds at this reset date and issue a replacement in line with market expectations. Post the $575M February equity raise and debt consolidation, Contact is well positioned to advance investments aligned with Contact31+ Closing net debt, $M Face value of borrowings less cash Interest rate, % Weighted average gross interest1 on average borrowings Net debt to EBITDAF, X Includes S&P adjustments2 Borrowing maturities, $M Average tenor of 7.2 years as at 30 June 2026 Streamlined balance sheet 1. Gross interest includes all interest on borrowings, bank commitment fees and deferred financing costs. Unwind of leases, provisions and capitalised interest not included. | 2. Illustrated here on a point basis based on expected S&P adjustments. See breakdown of S&P approach on slide 47. 774 1,025 1,831 2,314 21 -514 -766-150 FY21 25 -168 FY22 49 1,474 -140 FY23 47 -229 FY24 50 FY25 63 2,905 FY26 645 882 1,383 1,649 1,850 2,202 Lease obligations Borrowings Cash on hand 250 350 434 435 1,011 225 250150 350 FY27 FY28 300 FY29 FY30 FY31 FY32 FY33 FY52 FY55 400 650 Undrawn bank facilities Domestic bonds Capital bonds AMTN EMTN 1.4 1.8 2.6 2.7 2.3 2.1 FY21 FY22 FY23 FY24 FY25 FY26 974 892 1,310 1,727 1,973 5.2% FY21 5.4% FY22 5.8% FY23 6.1% FY24 5.8% FY25 5.2% 3,057 FY26 Average gross interest Average gross debt FY26 results: Key balance sheet metrics
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21 Dividend for FY26 of 40 cents per share • The final dividend of 24 cents per share is imputed up to 79% or 19 cents per share for qualifying shareholders. • This takes the total FY26 dividend declared to 40 cents per share, representing a pay-out of 65% of FY26 operating free cash flow and 114% of the average operating free cash flow over the preceding 4 financial years (FY22-FY25). • The record date is 18 August 2026; payment date is 23 September 2026. • The NZD / AUD exchange rate used for the payment of Australian dollar dividends will be set on 25 August 2026. Dividend per share for FY26 up 3% to 40cps 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 FY26 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 19 August 2026 to confirm participation in the plan. • The trading period for setting the price for the DRP is 17 August 2026 to 21 August 2026. The DRP strike price will be announced: 25 August 2026. Ordinary dividends, $M Declared Final dividendInterim dividend % pay-out of annual operating free cash flow 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 FY26. If the shares issued in FY26 as consideration for Manawa, the February 2026 equity raise, and the acquisition of KCE are excluded, the dividend declared would represent a pay-out of 50% of FY26 operating free cash flow and 89% of the preceding 4-year average. 326 261 FY22 333 266 82% FY23 318 256 92% FY24 352 282 101% FY25 368 294 114% FY26 330 282 ➢ Annual operating free cash flow 100% 80% Dividend level as a % of preceeding 4yr operating fcf 164 165 181 227 260 109 109 110 128 159 FY22 FY23 FY24 FY25 FY26 273 274 291 355 419 cps 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 expects to lift the total dividend in FY27 to 42 cents per share.1 ‒ On this basis, dividends in FY27-FY28 are expected to be imputed up to ~70%. • Reliable ordinary dividends are expected to increase over time with growth in operating free cash flow. Reflects 65% of FY26 operating free cash flow and 114% of the average operating free cash flow for the preceding four years 65% 648 40
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22 Normalised and expected FY27 EBITDAF $1,045M1 Assumptions based on mean hydrology and wind conditions $299M$90/MWh3,335GWhStrategic fixed price $367M$155/MWh2,370GWhCFDs $335M$168/MWh1,995GWhC&I $652M$171/MWh3,810GWhRetail $116MOther income4 $1,769M -$0M$0/MWh5,850GWhHydro mean -$11M$2.5/MWh4,635GWhGeothermal average -$52M$178/MWh5291GWhThermal -$102M$107/MWh950GWhRenewable PPAs -$82M$193/MWh6x425GWhMarket acquired -$247M -$98MTransmission/Storage$56MLength7 -$360MOpex BAU-$56MLocation losses8 -$7MOpex – Integration costs -$12MOpex – SaaS implementation cost -$379MTotal Opex -$477MTotal $0MTotal * Fuel is natural gas, carbon and PPA costs. 2,324 46 Channel choices maximise long term value21 Net price3 driven by best commercial practices2x = FY assumptions that deliver expected & normalised EBITDAF for FY27 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 = = = = = = 1,895 100 3,810 3,335 CFDs C&I Retail Strategic fixed $155/ MWh $168/ MWh $171/ MWh** Contracted Uncontracted 1,769 -247 -98 -360 0 1,045 -19 x 53 48 42 38 55 107 116116 152 152 152 42 40 35 45 80 94 135 68 50 Aug- 26 Sep- 26 Oct- 26 Nov- 26 31 Dec- 26 Jan- 27 Feb- 27 Mar- 27 Apr- 27 May- 27 Jun- 27 ASX Futures, $/MWh At 23 Jul 2026 $90/ 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). | 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, irrigation and other income. | 5. Gas price of $15/GJ, carbon price of $59/unit and thermal portfolio heat rate (9.8GJ/MWh). | 6. Acquired generation price includes premiums paid for HFO and NZAS demand response. | 7. Length of 557GWh assumed. | 8. Locational losses of 5.6% on spot purchases and settlement of CFDs sold at a wholesale price of $87/MWh. = Trading delivers value to largely offset locational losses5 Digitalisation & continuous improvement optimise fixed costs6 Opex (BAU) $M ** Retail volume contracted. Competitive risk remains on pricing achieved. Note: All figures are subject to rounding. GWh: = = Integration & Saas implementation
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23 Strategy update
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Empowered people and leaders Unite our people behind Contact31+ and develop NZ’s best energy leaders Relationships with our stakeholders Maintain enduring trust with stakeholders, investing for secure, affordable renewable energy while upholding our environmental commitment Productivity Drive disciplined growth by simplifying processes and deploying automation Tech advantage Establish a distinctive edge in data and AI on a simplified and secure technology platform Extend our advantage as NZ’s geothermal leader Scale on high-quality existing fields, explore new options, and continue to improve our cost-leadership position Build into new demand with wind and solar Deliver lowest-cost diversified wind and rapidly deploy solar, anchored on long-term industrial partnerships Lead the energy transition at home Empower our customers to shift energy use, while making every interaction easy and personal Lead on new flexibility in NZ Accelerate batteries, build advantage in hydro flex and maintain gas flex, optimising our portfolio in real time Strategic pillars Leading New Zealand’s renewable energy future Values Performance edge Own the future Brave humility Underpinned by continued operational excellence across our diverse and resilient portfolio Enablers 24
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25 Contact31+ is anchored on building renewables in connection with long-term industrial partnerships Data Centres Metals Electrification of dairy Opportunities for new electricity demand exist at scale across key sectors Tangata whenua relationships Environmental stewardship Grid / network connectivity Fuel flexibility management Local government engagement Sustainable business practices Planning and project governance Energy firming and resilience Community involvement Consenting processes Local contracting relationships Flexible load contracting Dairy decarbonisation could see 1.8 – 4.6TWh2 of new demand Opportunities totalling 4 – 6TWh1 from existing and proposed sites Announced metals projects could add >600GWh3 of new demand Enabling capabilities:Contact can draw on its deep set of enabling capabilities to support customer energy transition and growth 1. Based on ~185MW total capacity at existing sites, with ~15% average 2025 utilisation estimated, and the disclosed, uncommitted pipeline capacity across major existing and potential large operators. | 2. Includes known and committed biomass and electricity conversions. Upper bound is based on manufacturing and fuel use disclosure in Fonterra’s FY25 Climate Statement. Suitability for electrification to be confirmed. It is expected a portion of load from shifting dairy manufacturing away from coal will go to biomass. | 3. Includes NZ Steel’s Electric Arc Furnace and the potential reopening of NZAS Line 4 potline. The consented National Green Steel EAF presents further upside.
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26 Total uncommitted generation pipeline of 11TWh+, provides optionality to meet demand as it materialises We are advancing 4TWh+ of development options, to be anchored on long-term industrial partnerships Huriwaka 250MW | 890GWh Southland wind >325MW | 1,210GWh Te Mihi Stage 3 Up to 100MW | 830GWh1 (Up to ~300GWh net uplift)2 Tauhara 2 50 – 70MW | 415 – 580GWh Stratford BESS 200MW | 400MWh Argyle 80MWac | 180GWh Stratford Solar (hybrid) 150MWac | 312GWh 1. Ultimate size is subject to additional consented mass-take. | 2. Represents potential net uplift in output after accounting for the planned closure of the Wairakei geothermal station. | 3. Fluid take is partially consented. Ultimate size is dependent on additional land access and consented mass-take. | 4. Te Mihi Stage 3 is included on a net uplift basis. Consent granted In Fast-Track Contact31+ priority development options, representing ~4TWh of net new renewable output And can draw additional projects from our 11TWh+ total pipeline as customer needs evolve Tauhara 3 Up to 100MW | 830GWh3 High priority proposed Contact31+ growth projects subject to FID Future development pipeline options under assessment 11 Solar Geothermal4 Wind 0.5 0.7 Renewable generation development pipeline options, TWh 4 7 7TWh 4TWh
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27 A pathway is in place for NZAS to act as long-term customer underpinning Contact’s 1TWh+ Southland Wind Farm Electricity stats Up to 55 Turbines >325MW total capacity Average annual output expected to be >1,210GWh Non-binding letter of intent (LOI) signed with Rio Tinto for a PPA to support the potential restart of 50MW Line 4 potline at NZAS. Consent approved April 2026. Specialised infrastructure advisor, Mafic, appointed to run identification and selection process for a strategic partner for Contact’s extensive wind pipeline. We have engaged a shortlist of credible wind partners. Project updates Contact is advancing strategic partner identification and targeting mid-2027 for Final Investment Decision
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28 High-capacity fibre connectionSolar and battery development options Available transmission capacity Diverse high-capacity fibre, both terrestrial and subsea, provides connection to Auckland where New Zealand’s international cables land. 350MW transmission capacity available within 1-2 years with minimal substation work. 600MW expected to be available within 2-3 years following planned upgrades.3 150MWac / 312GWh p.a. solar farm in consenting, with DC coupled batteries potentially providing up to 750MWh storage.2 500MW grid-scale battery capacity consented. Land owned and under option Existing site complemented by significant adjacent land options. Able to support scalable renewable and load growth opportunities. Long-term member of the community 50 years operating in the Stratford community. Long-standing relationships with local stakeholders including councils and tangata whenua. 1. IT / compute load of 250MW. Approximately 350MW total load including ancillary load at peak times (subject to final design). | 2. Based on batteries with 5-hour duration. | 3. BCG analysis based on Transpower data and disclosures. Following the March 2026 closure of Contact’s Taranaki Combined Cycle baseload gas plant (TCC), Contact is taking steps to leverage the unique combination of site resources and support growth in the Taranaki region Contact and CDC will seek resource consent for a 250MW data centre1. It would be supported by co-located battery storage development. Current activities focus on consenting, site and infrastructure design, customer engagement and development planning. Contact has partnered with CDC to explore data centre development at its highly strategic Stratford site Existing generation The operation of Contact’s existing 200MW fast-start gas peaking assets at Stratford is not impacted by the data centre concept. .
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29 Extend our advantage as New Zealand’s geothermal leader Build into new demand with wind and solar Lead the energy transition at home Lead on new flexibility in New Zealand Strategic pillars FY27 pillar targets • Te Mihi Stage 2 on track (for delivery FY28) • Tauhara 2 FID taken1 • Tauhara 3 option progressed • 0.5TWh industrial energy demand electrified • Kōwhai Park solar delivered • FID on 1-2 additional solar farms1 • 1+ wind farms consented • Glenbrook-Ohurua 100MW battery delivered • Additional 200MW battery under construction • Manawa portfolio benefits of $10-20M p.a. delivered • Future technology stack selected and execution commenced • Cost-to-serve $135 per customer2 • 15 – 20MW retail demand flex under management Benefits of productivity programme clear Manawa benefits delivered 42cps dividend in FY273 FY27 financial targets 1. Each FID to be considered in isolation with all information available at the time. Pending appropriate market conditions and projects meeting returns thresholds. | 2. Cost-to-serve per customer (real 2026). Target rebaselined to include all direct and indirect retail opex other than cost to acquire (previous method did not include all indirect costs allocated from corporate). Will be measured excluding any SaaS implementation costs associated with investment in future retail platform. This differs from $/connection previously measured under Contact26. | 3.All future dividend decisions are at the discretion of the Board at the time. What you can expect from us in the next 12 months We have already accelerated the delivery on a number of our FY27 Contact31+ strategy pillar targets Accelerated / early (FY26) delivery
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30 Questions
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31 Supporting materials Market update
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32 National electricity demand Source: EMI, Contact. Does not include NZAS. National electricity demand, TWhRegional change, % FY26 vs FY25 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 up ~3% (up ~1% normalised for NZAS demand response) National electricity demand in FY26 was up ~3% year-on-year to 42TWh. Adjusting for NZAS demand response – called by Meridian in 1H25 to support challenging hydro conditions – demand was up ~1%. Demand at the Central North Island node was down 15% due to the impact of the Winstone Karioi pulp mill and Tangiwai sawmill closures in August 2024, reflecting broader challenges in wood and paper processing without the protection of fixed price electricity hedging. Huntly node demand increased 7% in FY26, due to population growth in the Waikato/Hamilton region and increasing electricity use from electrification and industrial customers. Seasonal conditions at irrigation nodes, along with population growth, have resulted in a 4% increase in demand in South Canterbury. Southland demand growth appears to be driven by ongoing industrial electrification, particularly in the dairy and meat processing sectors, alongside broader regional growth. 0% 7% 1% 4% 0% (0%)(2%) 0% 8%* 4% 0% 1% (15%) 1% 3% 1% 4% 1% 5.1 4.9 5.0 5.0 5.0 4.2 5.0 10.3 10.6 10.2 10.5 11.2 10.9 11.1 25.8 26.1 25.8 25.6 25.9 25.7 25.9 FY20 FY21 FY22 FY23 FY24 FY25 FY26 41.2 41.6 41.1 41.1 42.1 40.9 42.0 +2% +3% North Island South Island (ex NZAS) NZAS 3%
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33 Hydro generation was up ~15% on FY25, driven by high inflows from Q2 FY26. Impacts included: • The lowest thermal generation share since the introduction of the market (~6%). • Lower spot wholesale prices than in FY25. • Lower total industry carbon emissions. Geothermal generation volume was up ~6% with the addition of TOPP 2 and Ngā Tamariki OEC5 in 2H26 and a full operational period of Te Huka 3. Solar increased from 17GWh to ~270GWh, ~0.7% of total market generation. Battery storage discharged ~40GWh during the period.2 Generation by type, TWh • FY26 began with storage levels close to the post-market average before a short dry spell saw levels draw down over winter. Hydro storage reached its lowest level in August 2025, some 0.5TWh higher than the lowest point in August 2024. • Strong inflows from September drove a rapid recovery, with storage peaking in December 2025. • Drier conditions followed through the second half of the year, although storage remained above historical averages for the remainder of the period, closing with national hydro storage 135% of post- market mean. 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 Jul- 24 Dec- 24 Jul- 25 Dec- 25 Jun- 26 1H25 1H26 National hydro storage, TWh Carbon emissions (mT) Source: EMI (generation data), MBIE (emissions data, Electricity data tables) and NZX Hydro data. 1. Carbon emissions for FY26 Apr-Jun quarter have been estimated using historic conversion rates with actual generation data. | 2. Battery storage discharge is not included in total generation numbers. Record renewable period Fuel supply High hydro inflows and new renewable generation online pushed thermal generation market share to its lowest since the market wasintroduced 2H262H25 2.9 2.7 2.9 0.3 3.5 3.7 3.8 7.6 9.0 9.6 23.9 21.4 24.7 2.4 1.7 0.53.9 4.2 2.3 FY24 FY25 FY26 Gas Coal Hydro Geothermal Wind Solar Non-identified 44.1 42.9 44.0 2.1 14.2 4.1 Mean Actual
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34 The market is responding to record investment in renewable generation and actions to reduce dry year risk Wholesale and futures electricity pricing, $/MWh Source: EMI wholesale pricing, OTA, to 30 June 2026. 0 50 100 150 200 250 300 350 400 450 Jun- 17 Jun- 18 Jun- 19 Jun- 20 Jun- 21 Jun- 22 Jun- 23 Jun- 24 Jun- 25 Jun- 26 Long-dated futures (>12 months) Short-dated futures (<12 months) Monthly average spot price 1. Change in ASX Settlement prices at Otahuhu for Q3 2026 from 31 Dec 2025 to 30 June 2026. Source: ASX.| 2. Company announcements and Contact’s analysis. | 3. 2025 real – Otahuhu Node OTA, Auckland. This is a through-the-cycle measure in a balanced market. Prices achieved are a function of the market at a point in time. Reliable, plentiful natural gas 5 year average spot price =$139/MWh 10 year average spot price = $127/MWh Gas outages & availability decline • Reduced thermal generation allowed more gas to be stored in AGS, while Genesis replenished its coal stockpile (backed by the HFO). As a result, short- dated futures moved lower alongside spot prices, responding to low risk of fuel scarcity in Winter 2026. • The low fuelling risk led to ASX settlement prices for Q3 2026 falling >60% over 2H FY261. Short-term pricing (reflected in short-dated futures) • Long-dated futures declined 27% over 2H FY26, reflecting an expectation that the market is largely moving back into supply / demand balance. • ~3TWh of generation either committed or under construction and expected to come online by 20272. • Contact expects the long-term wholesale price to settle around $115-125/MWh3 reflecting the marginal costs of new renewable projects and the costs associated with firming renewable intermittency. Long-term pricing (reflected in long-dated futures) • Spot wholesale electricity prices fell sharply following Winter 2025 as intense rainfall and high wind conditions lifted renewable generation volumes. • This displaced the need for thermal generation (leading to the lowest thermal generation market share since the introduction of the market). • These conditions led to the lowest recorded monthly average spot price in January 2026 ($4/MWh). FY26 spot wholesale pricing Wholesale market pricing
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35 Retail electricity market connection trends • Retail competition remained active, with customer churn broadly unchanged at ~19.5%. • Tier 1 retailers now hold ~86% market share. Growth over the last 2 years was led by Meridian (+12% over two years, excluding Flick), followed by Contact (+6%) and Mercury (+3%). • Genesis’ decline has been driven by the closure of Frank Energy (announced June 2025) and a shift to focus on margin quality over raw customer numbers. • Tier 2 retailers held steady, while Nova fell by 9%. The ~41k connection loss across Tier 2 retailers was largely driven by Meridian’s acquisition of Flick Energy in May 2025. • Contact added 27k electricity connections over the past two years, resulting in a 20% market share. Change in retail customer electricity connections, ‘000s 30 June 2024 – 30 June 2026 2yr % change2yr ICP delta (1000s) Retail electricity tariff changes, c/ kWh Tier 2: -41k connections Retail pricing trends • Residential electricity prices have risen steadily, at a compound annual growth rate of ~6% over the five years to March 2026. • Average prices increased ~11% in the year to March 2026, reaching 38.3 c/kWh. • The lines component rose 13%, while the energy and other component increased 10%. • Cost pressures on the lines component of the tariff are expected to remain as the increased cost of transmission and distribution infrastructure continues to be incurred.2 • Moderating wholesale prices are expected to lower the electricity component over time. 12 months ended: Tier 1: +93k connections Source: EMI – residential ICPs only Source: MBIE 18.6 19.5 20.7 20.9 23.0 11.6 12.0 12.4 13.5 15.3 Mar-22 Mar-23 Mar-24 Mar-25 Mar-26 30.2 31.5 33.1 34.4 38.3 +6% Competition remains strong as Tier 1 retailers extend market share leadership Retail electricity market Lines (c/kWh) Energy & Other (c/kWh) 1 1. Compound annual growth rate. | 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). Costs are increasing annually. 6% 3% 24% -9% 2% 3% 1% 11% -30 -20 -10 0 10 20 90 -40 -6% Genesis Mercury Meridian Nova Pulse Electric Kiwi 2Degrees/ Vocus OtherContact Breakdown of an average household electricity bill 38.5% 8.0% 24.5% 11.0%13.0% 4.5% 0.5% Generation Transmission Distribution Metering Retail GST Levies Source: Electricity Authority
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36 Supporting materials Financial results
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37 Guidance topics FY27 Guidance CommentaryFY27 guidanceFY26 resultFY26 guidance1 $375M - $385M$387M$385M - $395MOther operating costs $360M$361M$360MOther operating costs – BAU2 Reflects costs of implementing new systems designated as SaaS, reduces SIB capex, includes costs to FID for the Future Retail Platform.$10M - $15M--Other operating costs – SaaS Non-recurring costs relating to the Manawa acquisition.$5M - $10M$26M$25M - $35MOther operating costs – Manawa integration and transaction $178M - $188M$145M$170M - $185MStay in business (SIB) capex (cash) $134M - $139M$82M$115M - $125MSIB capital expenditure BAU Completion of programme in FY26.-$14M$12M - $13MSIB accelerated programme Spend brought forward into FY26 with remainder expected in FY28. -$15M-SIB capital expenditure Tauhara spare rotor Completion of extension work activities to occur within FY27.~$17M$21M$20M - $25MSIB capital expenditure Wairakei Continued upgrade work on Highbank and Coleridge hydro sites. $7M - $12M$5M $18M - $22M SIB capital expenditure Manawa refurbishment Decommissioning relating to TCC and Wairakei. ~$5M$1MSIB capital expenditure decommissioning provisions -$5MSIB capital expenditure Geothermal Wells Completion of system integration from Manawa transaction. ~$15M$2MSIB capital expenditure integration Te Mihi Stage 2, Glenbrook-Ohurua Battery 2 and pre-FID activity. $460M - $470M$375M$500M - $510MGrowth capital expenditure (cash)3 Increase with Battery and Wairakei depreciation and increase in digital assets.$310M - $320M$294M$280M - $290MDepreciation and amortisation $120M - $130M$140M$115M - $125MNet interest (accounting) $100M - $110M$122M$105M - $115MCash interest (in operating cash flow) FY27 lower tax due to benefits of investment boost policy and tax credit on decommissioning of TCC. $80M - $90M$119M$120M - $130MCash taxation Including (gains) / losses on ASX market making.$5M - $10M($4M)$5M - $10MRealised (gains) / losses on market derivatives not in a hedge relationship Increase in the ordinary dividend to reflect benefits of the Manawa acquisition.42 cps40 cps40 cpsTarget ordinary dividend per share Increase due to impact of lower cash tax and higher capitalised interest due to Te Mihi Stage 2 and Glenbrook-Ohurua Battery 2. 65 - 70%64%~50%Operating cash flow conversion 1. Updated at 1H26 results. | 2. Includes corporate costs (ex integration and transaction) of $69M in FY26 (vs. $60-70M guidance) and ~$65M in FY27 guidance. | 3. Growth capital expenditure includes capitalised interest.
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38 $376M$95/MWh 3,960GWhStrategic fixed price $264M$155/MWh1,700GWhCFDs $289M$165/MWh1,750GWhC&I $627M$164/MWh3,825GWhRetail $100MOther income4 $1,656M -$0M$0/MWh5,750GWhHydro -$20M$4/MWh4,950GWhGeothermal -$59M$215/MWh5275GWhThermal⁴ -$83M$100/MWh830GWhRenewable PPAs -$52M$260/MWh200GWhMarket acquired6 -$214M -$90MTransmission/Storage$139MLength7 -$370MOperating expenses – BAU -$140MLocation losses8 -$35MOpex - integration and transaction costs -$405MTotal Opex -$495MTotal-$1MTotal FY26 assumptions that deliver normalised & expected EBITDAF of $945M over a financial year Hydrology & asset availability optimise generation3 4 Totalx = Access to and price of fuel* drives financials & risk position Channel choices maximise long term value21 Net price3 driven by best commercial practices2 Totalx = Trading delivers value offsetting locational losses5 Digitalisation & continuous improvement optimise fixed costs6 x x x x x x x = = = = Normalised and expected EBITDAF assumptions1 FY26 results With reconciliation to actual performance x x = = = = Normalised & Expected FY26 at start of year Lower renewables FY26 EBITDAF normalised for non-recurring Manawa transaction and integration costs Renewable generation below mean (-754GWh) Calculated at thermal SRMC Fixed costs Transmission & storage costs were $18M lower than forecast, supported by LCE rebates. Reclassification of $10M to fixed costs. Integration & transaction costs were $9M lower than forecast. Non-recurring Manawa related costs Reported FY26 EBITDAF 132 25 94 34 36 26 8 945 1,011 1,037 Lower thermal heat rate due to final run of TCC and acquired generation price lower than assumed (-$80/MWh) Market channel price Lower GWAP on merchant sales was more than offset by very low location losses. Contact’s LWAP/GWAP spread reduced to ~1% Lower sales volumes were offset by meeting sales with lower thermal and more acquired generation at lower prices Net volume impact Increased long-term channel price Retail net price outperformed guidance assumption by $10/MWh = Gas, carbon, acquired generation price $M 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). | 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, broadband gross margin, irrigation and other income. | 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 for FY26 assumed. | 8. Locational losses of 6.5% on spot purchases and settlement of CFDs sold at a wholesale price of $180/MWh.
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39 57 76 100 939 -265 -291 -315 -346 -459 -85 -56 -74 -80 -185 -94 -269 -326 -256 1,023 FY22 FY23 1,269 53 FY24 1,476 50 FY25 1,640 -14 FY26 Electricity sales margin Other gross margin Fixed operating costs Location losses Variable fuel costs 546 573 663 774 1,011 Operating earnings (EBITDAF) 106 115 127 136 132 3.69 1.39 FY22 3.73 1.42 FY23 3.80 1.22 FY24 3.69 1.73 FY25 3.68 3.91 FY26 5.08 5.14 5.02 5.42 7.58 Retail Long-term sales 117 126 116 200 138 1.13 0.39 FY22 0.52 0.15 FY23 1.62 0.59 FY24 1.09 0.46 FY25 0.23 0.68 0.83 FY26 1.52 0.67 2.20 1.55 1.74 Thermal Acquired PPA Purchases Electricity sales Variable fuel costs 1 1 1 1 1 3.94 3.28 FY22 3.92 3.19 FY23 3.63 3.39 FY24 3.30 4.54 FY25 5.03 4.91 0.01 FY26 7.22 7.10 7.02 7.84 9.96 Hydro Geothermal Battery (i) Renewables (ii) Thermal, acquired and PPAs 133 133 150 186 155 0.94 2.10 0.63 FY22 1.10 1.44 0.09 FY23 1.13 2.57 0.51 FY24 1.17 2.30 0.51 FY25 1.86 2.01 0.23 FY26 3.66 2.63 4.21 3.97 4.10 Commercial and Industrial CFDs Spot sales (i) Long-term channels (ii) Market channels Price ($/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 46 for a definition and reconciliation of EBITDAF. 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 $98M in FY25. 117 121 137 158 140 8.739 7.772 9.232 9.390 11.687 Price ($/MWh) Volume (TWh) Historic performance
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40 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 expressed as absolute emissions reductions and measured on a calendar-year basis. | 3. The target for Scope 3 emissions from use of sold products increased due to Contact’s role in supplying gas to essential All-of-Government public services. FY26FY25FY24FY23FY22TargetUnitIndicator 317,255740,468947,491526,621786,84245% reduction of 2018 Scope 1 and 2 emissions by 2026, equivalent to 647,443 tCO2e. 2 tCO2eDirect GHG emissions (Scope 1) 316,112739,790947,131526,282786,544tCO2e- Stationary combustion (generation) 824409332307297tCO2e- Mobile combustion 5011428321tCO2e- Fugitive emissions 269155tCO2e- Stationary combustion (ancillary equipment) 2,4601,1839751,9571,399tCO2eIndirect GHG emissions (Scope 2) 319,715741,651948,466528,579788,241tCO2eSub-total Scope 1 and 2 390,731369,583265,034273,673394,784tCO2eIndirect GHG emissions (Scope 3) 15,5178,7996,5226,1976,37134% reduction of 2018 Scope 3 GHG emissions from use of sold products by 2026, equivalent to 244,311 tCO2e. 2 45% reduction of 2018 Scope 1 and Scope 3 emissions from all sold electricity by 2026, equivalent to 688,253 tCO2e. 2 tCO2e- Category 1 – Purchased goods and services 79,63487,20379,18588,26657,876tCO2e- Category 2 – Capital goods 4,2518,0065,1301,050149,743tCO2e- Category 3 – Fuel and energy1 478205254108444tCO2e- Category 4 – Upstream distribution and transportation 93695847108tCO2e- Category 5 – Waste 1,7201,0811,6011,274567tCO2e- Category 6 – Business travel 2,044956927965832tCO2e- Category 7 – Employee commuting 267,348250,612170,929175,603178,554tCO2e- Category 11 – Use of sold products3 8,678339429164289tCO2e- Category 13 – Downstream leased assets 11,97912,313---tCO2e- Category 14 – Investments 711,4561,111,2351,213,500802,2521,183,025tCO2eTotal Scope 1, 2 and 3 emissions
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41 Growth capital expenditure 1. Excludes ~$0.6M of development capex that was incurred by Manawa prior to acquisition. | 2. Total under current board approvals. | 3. Additional funding was approved in FY26 to close out the Tauhara project including replacement of pipework and acid dosing systems. | 4. For Te Mihi Stage 2 at FID, 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. | 5. Relates primarily to deployment of demand flex technology and Clutha consenting. | 6. Solar covers both Kōwhai Park and Glorit investment and excludes pre-FID development expenses for solar which are captured within receivables. Glorit obtained Financial Close during FY26. Growth capital expenditure – cash basis, $M¹ Total²Remaining under current approvals 12 months ended 30 June 2026 Up to 30 June 2025 940827905Tauhara3 305310292Te Huka 3 712305205201Te Mihi Stage 24 3861121Wind 163155691Glenbrook-Ohurua Battery 1 235207271Glenbrook-Ohurua Battery 2 392316-Tauhara Unit 2 211219Other5 33511721196Capitalised interest 2,7896863751,727Total Contact’s FY26 growth investment demonstrates progress in the strategic execution of its renewable development pipeline Project status • Construction commenced in FY25 on three major renewable projects: Glenbrook-Ohurua Battery 1, Kōwhai Park solar and Te Mihi Stage 2 geothermal. Contact’s first battery is now operational, with final costs and close out activities to come. • Construction of Glenbrook-Ohurua Battery 2 commenced during FY26 and Notice to Proceed was issued to the EPC contractor for Glorit solar. • Construction of the Tauhara and Te Huka 3 geothermal plants is now complete, with remaining spend relating to final close out activities. • Tauhara 2 is now in the Select stage as well as pre-FID drilling works. • Contact does not currently have any wind projects under construction. The reported wind development spend reflects pre-FID activity only. Total²Remaining under current approvals 12 months ended 30 June 2026 Up to 30 June 2025 866322-Solar6 9216CO2 840183Forestry 179652489Total Investment in joint ventures and associates, $M FY26 results: Cash flow Financial treatment • 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 investments in the Kōwhai Park solar farm and Glorit solar farm are accounted for as investments in joint ventures and associates, and are therefore excluded from growth capital expenditure.
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42 Output from Contact generation and renewable PPAs sold to the national grid, GWh Generation and sales position 3,333 3,114 3,283 3,185 3,388 4,543 4,914 3,752 3,698 3,940 3,919 3,628 3,297 5,0321,360 1,592 1,046 1,620 1,088 229 FY20 FY21 FY22 FY23 FY24 FY25 11827 FY26 8,445 8,404 8,269 7,543 8,636 8,928 11,013 439 Operational data Renewable % 84% 81% 87% 98%94% 81% 88% Geothermal generation, GWh FY26 geothermal generation was 371GWh higher than FY25. A full period of generation Te Huka 3 was partially offset by statutory outages at Te Huka 3, Tauhara and Wairakei. 1,415 1,240 1,386 1,380 376 1,045 1,081 1,055 998 1,405 1,255 1,261 335 339 331 308 1,064 1,287 1,384 340 299 322 323 274 986 1,062 198 155 189 176 316 300 309 203 277 316210 206 FY20 FY21 FY22 FY23 127 FY24 229 FY25 FY26 3,333 3,114 3,283 3,185 3,388 4,543 4,914 Hydro generation, GWh Thermal generation, GWh 871 1,126 673 164 1,395 692 147 291 234 179 148 223 378 195 213 190 125 78 379 FY20 1881 FY21 481 FY22 2 FY23 1 FY24 18 FY25 081 FY26 1,439 1,673 1,127 517 1,620 1,088 229 Thermal generation was 859GWh lower than FY25 due to high hydro inflows and additional renewable generation brought online in the last 18 months displacing both Contact, and the market’s, need for thermal generation outside of winter 2025. Following the closure of TCC, Contact’s mean expected thermal volume is now 250 – 300GWh p.a. Te Huka Ōhaaki Poihipi Wairakei Te Mihi Tauhara Te Huka 3 Whirinaki Te Rapa - direct Te Rapa - spot Stratford Peakers TCC Battery Renewable PPAs Thermal Hydro Geothermal 1,657 1,667 1,775 1,740 1,594 1,445 1,480 2,095 2,031 2,165 2,179 2,034 1,852 1,979 669 904 FY20 FY21 FY22 FY23 FY24 FY25 FY26 3,752 3,698 3,940 3,919 3,628 3,297 5,032 North Island South Island - ex Clyde & Rox Clyde Roxburgh
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43 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 0 100% 90 FY20 98% 87 FY21 100% 89 FY22 98% FY23 100% 91 FY24 95% 87 FY25 97% 89 FY26 89 +4% 31.1 30.5 31.0 30.4 29.2 29.7 29.9 FY20 FY21 FY22 FY23 FY24 FY25 FY26 +1% Geothermal fuel performance Taranaki combined cycle (TCC) Hydro Geothermal2 Stratford Peakers Plant availability1 1. Availability Factor calculation includes all station outages (Planned, Maintenance, Forced) but not plant deratings. | 2. 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. | 3. Statutory 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. Excludes impact of reduced Wairakei field output in FY27 associated with Wairakei station decommissioning and switchover to Te Mihi Stage 2. Diesel Peakers Despite a planned outage at Wairakei in FY26, total mass extracted, and extracted volumes as a % of consented mass take, were up on FY25 (which included a planned outage (25 days) at Te Mihi and an electrical outage at Wairakei A&B station). Upcoming geothermal statutory turnarounds (outages)3 Frequency & typeFYImpact (GWh) Plant 4y Stat Turnaround2716Te Huka 1&2 4y Stat turnaround + ext works27320Wairakei 4y Stat turnaround2831Poihipi Y1 Stat Turnaround2873Te Mihi Stage 2 Y3 Stat Turnaround28169Tauhara Y3 Stat Turnaround2857Te Huka 3 4y Stat turnaround29158Te Mihi Pool revenueElectricity Output, GWh Capacity factor AvailabilityNet capacity MW $M$/MWh 12118067320%84%377FY22 181071645%85%377FY23 2571841,39542%82%377FY24 22933069221%89%377FY25 271831479%93%377FY26 Pool revenueElectricity Output, GWh Capacity factor AvailabilityNet capacity MW $M$/MWh 4781213,94057%83%784FY22 290743,91957%84%784FY23 5941643,62853%90%784FY24 5381633,29748%87%784FY25 410815,03240%78%1,295FY26 Pool revenueElectricity output GWh Capacity factor AvailabilityNet capacity MW $M$/MWh 4581403,28391%97%425FY22 254803,18589%94%410FY23 6011773,38889%94%586FY24 8451864,54384%90%649FY25 360734,91488%92%649FY26 Pool revenueElectricity Output, GWh Capacity factor AvailabilityNet capacity MW $M$/MWh 3821217910%53%202FY22 312071488%77%202FY23 3917522312%50%202FY24 8221737822%70%202FY25 10122814%85%202FY26 Pool revenueElectricity Output, GWh Capacity factor AvailabilityNet capacity MW $M$/MWh 259740%95%158FY22 1.249120%82%158FY23 1.168710%97%158FY24 12661181%92%158FY25 0.112200%95%167FY26 Operational data
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44 Hawea storage, GWh Gas storage, PJ Closing storage Closing storage (current) Fuel storage movements Source: NZX Hydro data 113 252 188 141 85 263 160 275 322 265 242 232 330 174 377 252 -183 -326 -291 -286 -151 -278 -263 -265 1H23 2H23 1H24 2H24 1H25 2H25 1H26 2H26 Inflows Opening storage Releases 253 191 139 87 264 160 275 261 4.7 2.4 3.4 2.8 1.6 3.4 3.3 3.9 2.7 1.7 0.9 1.3 3.1 1.9 2.1 0.9 -0.7 -0.7 -1.5 -2.5 -1.3 -2.0 -1.6 -0.9 -4.3 1H23 2H23 1H24 2H24 1H25 2H25 1H26 2H26 Gas Injected Gas Extracted Opening Storage 2.4 3.4 2.8 1.6 3.4 3.3 3.9 3.8 Operational data 4 Balance classified as long term storage (PJ) 4 4 4 4 4 4 4 Transferred to long-term storage
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45 Contracted gas volumes, PJ Uses of gas, PJGas storage monthly injections and extractions, PJ Contracted and stored gas Gas injected Gas extracted 5.4 5.9 6.5 7.0 5.4 3.0 3.0 3.0 2.25.0 3.0 2.6 2.2 2.8 2.8 2.8 3.8 0.2 CY261 CY27 CY28 CY29 CY30 CY31 CY32 CY33 CY34 CY352 9.0 8.4 8.5 8.6 9.7 8.1 5.8 Aug- 25 -0.13 0.24 Sep- 25 -0.50 0.00 Oct- 25 -0.76 0.01 Nov- 25 -0.61 0.02 Dec- 25 0.99 0.27 Jan- 26 -0.05 -0.08 0.17 Feb- 26 -0.14 0.030.29 Mar- 26 0.00 Jul- 25 0.26 Apr- 26 -0.32 0.01 -0.17 May- 26 -0.17 0.20 Jun- 26 -0.02 16.1 15.1 15.5 8.8 -3.0 1.9 -1.6 -6.1 -13.0 -9.2 -2.0 -2.8 -2.5 -2.2 -4.3 -4.2 -1.5 -2.6 -2.0 FY23 FY24 FY25 -0.5 FY26 Net extraction (injection) Generation Customer sales Wholesale sales Purchases Operational data 1. CY26 reflects actual volumes and forecasts for the second half of the year. | 2. CY26-CY35 reflects the maximum volume of gas available under contracts. Short-term gas Greymouth Pohokura
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46 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: Variance on prior year12 months ended 30 June 2026 12 months ended 30 June 2025 %$M Against underlying1ReportedReportedUnderlying1 62%162423331261Profit 7%21294273Depreciation and amortisation na(56)(21)35Change in fair value of financial instruments 40%40140100 Net interest expense 60%62166132104Tax expense 800%891Asset impairment / write- offs 31%2371,011872774EBITDAF Reconciliation between Profit and EBITDAF The movements between FY26 and FY25 underlying profit are as follows: • Depreciation and amortisation: increased by $21M as a result of an increase in fixed assets from the purchase of Manawa and a full year of Te Huka 3 depreciation. This has been partially offset by significantly lower usage of thermal assets compared to FY25. • Net interest expense: higher than FY25 as a result of additional borrowing to complete the Manawa acquisition and interest no longer being capitalised on Te Huka 3. • Tax expense: increased by $62M due to the tax impact of higher operating earnings. • Asset impairment / write offs: Asset write offs related to equipment replaced during first Tauhara outage (inclusive of pipework upgrade) and inventory related to TCC post decommissioning. Non-GAAP profit measure 1. All variances and commentary reflect movements in underlying performance. In FY25, reported results include a release of the AGS onerous contract provision of $98M pre-tax ($71M after tax). Underlying performance excludes the impact of the provision release.
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47 S&P Net Debt / EBITDAF ratio FY26FY25FY24FY23FY22$M EstimatedActuals from S&P ratings report Net Debt 3,0512,4491,9131,5561,099Carrying value of borrowings (90)(94)(41)(43)(55)Fair value adjustments 18116514212053 Restoration and environmental provisions net of tax (238)(238)(113)(113)(113)Hybrid bond credits1 (766)(514)(146)(89)(4)Accessible cash2 2,1381,7681,7631,431980S&P Adjusted Net Debt EBITDAF 1,011774663573546Reported EBITDAF (underlying) -(15)---Utilised AGS provision released (3)(13)(6)(27)(9)Realised gains/losses on market derivatives 75444Share based compensation 1411---Transaction costs related to the Manawa acquisition 1,029762661551541S&P Adjusted EBITDAF 2.12.32.72.61.8Net debt/EBITDAF (x) 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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48 Reconciliation of change in fair value of financial instruments DescriptionChangeFY25FY26Realised / unrealisedChange in fair value of financial instruments $M Realised gains or losses on the settlement of electricity derivatives entered into to meet Contact’s market making obligations 17(13)4Realised(A) Net market making Mark-to-market of open electricity derivatives in future periods 224 Unrealised Market making NPV of the changes to the forecast forward wholesale price path vs the wholesale path when the contracts were agreed (70)(7)(77)NZAS long-term sale CFD 37(13)24Kōwhai Park acquired PPA 66-66Mercury CFD (Manawa) Mark-to-market of open electricity / interest rate derivatives in future periods9(4)5Other non-hedged movements Contact recognises a share of the profit that joint ventures make in the Income Statement. This is the amount within their profit that relates to the joint venture’s unrealised derivative movements. (5)-(5)Share of unrealised gains/(losses) from joint ventures 39(22)17Unrealised(B) Unrealised movements in non-hedge effective electricity derivatives 56(35)21 Realised and unrealised Total change in fair value of financial instruments as per segment note (A+B) Commercial hedges recognised in EBITDAF that do not qualify for hedge accounting Financial contracts that hedge portfolio sales that are settled in the period(10)(5)(15) Realised Financial Transmission Rights (FTR) settlements and Exchange for Physical (ASX) Realised settlement (difference between the fixed contract and spot settlement) 92(134)(42)Net settlement of NZAS and Mercury contracts in the period 5-5Reclass share of unrealised gains/(losses) from joint ventures to Statement of Comprehensive Income 143(174)(31)Change in fair value of financial instruments as per Income Statement In the period, Contact acquired Manawa Energy and all of its associated long-term sales contracts. This included several major contracts for difference (CFD) that are not eligible for hedge accounting. The most significant of these is the sale of electricity to Mercury Energy. As with Contact’s existing CFDs ineligible for hedge accounting, movements in expected wholesale prices, when compared to forward wholesale prices when the contracts were entered into, drive changes in their recorded fair value. These non-cash movements, which relate to future periods, are recognised in the current period in the change in fair value of financial instruments line item. These movements increase the volatility of Contact’s reported Net Profit After Tax. Fair value of financial instruments
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49 Historical financial information FY26 FY25FY24FY23 FY22Unit ReportedUnderlying2ReportedUnderlying2ReportedUnderlying2 3,2063,3062,8672,1182,387$MRevenue1 2,1952,4342,5322,1922,2041,6131,5001,820$MExpenses1 1,011872774675663460573546$MEBITDAF 423331261235230127211182$MProfit 648434424282330$MOperating free cash flow 64.054.453.936.042.4cpsOperating free cash flow per share 4039373535cpsDividends declared 10,6616,8136,2085,8085,166$MTotal assets 5,4324,0533,5893,0042,326$MTotal liabilities 5,2292,7602,6192,8042,840$MTotal equity 3747423628%Gearing ratio3 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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50 FY26FY25 Year ended 30 June 2026Year ended 30 June 2025 GWAPVolumeGWAPVolume $M$/MWhGWh$M$/MWhGWhNote: this table has not been rounded and might not add 657179 3,675601163 3,689Electricity sales to Retail segment 3311512,189208 1331,566Electricity sales to C&I (netback) 1,270920CfDs – Tiwai support sales 677411Tauhara PPAs 1,517-CfDs – Mercury1 507394CfDs – Other Long term sales 1,6181,903CfDs and ASX - Short term sales 637114 5,589569157 3,629Electricity sales – CfDs 1,62414211,4541,3771558,883 Total contracted electricity sales 5 202475 21 229 Steam sales 2314Other income 2(12)Net income on gas sales 11-Irrigation net income 11Net income on electricity related services 374Net other income 1,66614211,701 1,386 1529,112 Total contracted revenue (323)(32)10,175(389)(44)8,928Generation costs2 (203)(134)1,512(122)(264)462 Acquired generation cost (526)(45)11,687(511)(54)9,390Generation costs (including acquired generation) 824 8110,1861,742 1958,928Spot electricity revenue 117771,512 116252462 Settlement on acquired generation 9418011,6981,8581989,390 Spot revenue and settlement on acquired generation (GWAP) (509)(87)(5,875)(1,143)(218)(5,255)Spot electricity cost (427)(76)(5,589)(695)(191)(3,629)Settlement on CFDs sold (936)(82)(11,464)(1,838)(207)(8,883)Spot purchases and settlement on CfDs sold (LWAP) 523420507 Trading, merchant revenue and losses 1,145895Wholesale EBITDAF2 -98Onerous contract provision unwind 1,145994Wholesale EBITDAF reported Wholesale segment Segmental performance 1. Mercury volume included from 11 July 2025 (completion of Manawa acquisition). | 2. FY25 EBITDAF (underlying) excludes the release of the AGS onerous contract provision equated to $98M.
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51 FY26FY25FY24FY23UnitResidential gasFY26FY25FY24FY23unitResidential electricity 71,53870,36968,09266,605#Average connections414,387401,332388,459380,482#Average connections 1,5211,5091,5841,504TJSales volumes2,8712,8092,7982,688GWhSales volumes 21.321.423.322.6GJ per ICPAverage usage6.97.07.27.1MWh per ICPAverage usage 63.052.945.142.1$/GJTariff348.4311.5287.9272.1$/MWhTariff -32.0-29.1-24.5-22.9$/GJNetwork, meters and levies-163.4-142.2-128.0-122.7$/MWhNetwork, meters and levies -17.0-11.0-9.8-10.1$/GJEnergy costs-191.2-174.5-158.8-138.6$/MWhEnergy costs1 -3.9-4.4-3.1-4.2$/GJCarbon costs-6.2-5.11.110.8$/MWhGross margin 10.18.57.74.9$/GJGross margin-43-36877$ per ICPGross margin 215182181112$ per ICPGross margin-18-14329$MGross margin 1513127$MGross margin FY26FY25FY24FY23UnitSME gasFY26FY25FY24FY23UnitSME electricity 3,8722,6622,9723,519#Average connections39,89341,65444,11346,962#Average connections 2,7216077941,063TJSales volumes582 651754794GWhSales volumes 703228267302GJ per ICPAverage usage14.615.617.116.9MWh per ICPAverage usage 37.638.531.025.2$/GJTariff355.4313.4282.2259.3$/MWhTariff -10.4-13.9-11.6-9.5$/GJNetwork, meters and levies-161.9-132.9-118.3-117.0$/MWhNetwork, meters and levies -17.0-11.0-9.8-10.1$/GJEnergy costs-190.8-174.5-157.3-138.6$/MWhEnergy costs1 -3.9-4.4-3.1-4.2$/GJCarbon costs2.75.96.63.6$/MWhGross margin 6.39.26.51.4$/GJGross margin409311262$ per ICPGross margin 4,4732,1301,750412$ per ICPGross margin2453$MGross margin 18651$MGross margin FY26FY25FY24FY23Retail segment EBITDAFFY26FY25FY24FY23UnitTelco -16-11832$MElectricity Gross margin136,730116,70995,16879,057#Average connections 3318179$MGas Gross Margin71.472.171.869.6$/cust/mthTariff 1713106$MTelco Margin-61.2-62.8-63.4-63.5$/cust/mthNetwork, provisioning, modems 34213547$MTotal Gross Margin10.39.38.46.2$/cust/mthGross margin 3479$MOther net income1713106$MGross margin -78-74-74-69$MOther operating costs -41-49-32-14$MRetail segment EBITDAF -2.7%-3.8%-2.6%-1.2%% EBITDAF margins (% of revenue) Retail segment Segmental performance 1. Energy costs reflect electricity purchased from solar customers: $1.2M in FY24, $2.7M in FY25 and $3.2M in FY26.