Earnings release
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22 2Q Earnings 26 Release auren AUGUST 2026
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2 CONTENTS Highlights ........................................................................................................................................................ 4 Message from Management ............................................................................................................................. 6 Electricity Market ............................................................................................................................................ 8 Operational Performance ............................................................................................................................... 11 Hydro .......................................................................................................................................................... 11 Wind ............................................................................................................................................................ 12 Solar ........................................................................................................................................................... 13 Curtailment and Modulation Gains ................................................................................................................... 15 Energy Balance .............................................................................................................................................. 16 Consolidated Energy Balance .......................................................................................................................... 16 Energy Balance - Generation Segment ............................................................................................................ 16 Energy Balance - Trading Segment .................................................................................................................. 18 Energy Balance of Noncontrolling Interests ....................................................................................................... 19 Consolidated Financial Performance ................................................................................................................. 20 Financial Performance – Generation Segment ................................................................................................... 27 Financial Performance of the Trading Segment .................................................................................................. 28 Financial Performance of Noncontrolling Interests .............................................................................................. 29 Other Material Information ........................................................................................................................... 30 Ordinance No. 140/2026 on the Commitment Term for Curtailment ..................................................................... 30 Corporate Reorganization ............................................................................................................................... 30 Contingent Liabilities...................................................................................................................................... 31 Quarterly Overview ....................................................................................................................................... 33
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3 Earnings Call August 06, 2026 (In Portuguese with simultaneous translation into English) 10:00 a.m. (Brasília) | 9:00 a.m. (New York) | 2:00 p.m. (London) Click here to view the webcast Earnings Presentation available at: ri.aurenenergia.com.br Contact Information Investor Relations o Mateus Ferreira (Financial and Investor Relations Vice President) o Marcelo Sá (Investor Relations Officer) o Juliana Ramirez (Investor Relations Manager) o Emille Reckia (Investor Relations Consultant) o Bruna Freixo (Investor Relations Analyst) o Bruno Tavares (Investor Relations Analyst) ri@aurenenergia.com.br ri.auren@aurenenergia.com.br As of June 30, 2026: AURE3: R$ 11.60 Market Cap: R$ 12.2 billion
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4 Highlights Portfolio resilience: the Company achieved modulation gains of R$ 70.5 million, partly mitigating the curtailment impact of R$ 97.8 million. The total modulation gain was 75% higher than in 2Q25 (R$ 40.4 million). This result reflects the Company's hourly generation profile, higher price volatility and higher average settlement prices during the quarter. In 6M26, the net effect of the portfolio is a negative R$ 16.3 million, resulting from a curtailment impact of R$ 184.0 million, partially offset by a positive modulation effect of R$ 167.7 million. Financial management discipline: net debt decreased by R$ 194.2 million in the quarter, while leverage rose marginally to 5.3x Net Debt/Adjusted EBITDA, due to the decline in EBITDA over the last 12 months (LTM). The deleveraging trajectory remains on track, with stabilization in 2026 and a decline from 2027 onward. Adjusted EBITDA: Auren recorded an Adjusted EBITDA of R$ 858.9 million in 2Q26, a 12.4% decrease compared to the same period last year, r eflecting the lower results from the Trading segment along with the reduced wind resources and higher curtailment compared to the same period in 2025. Progress in corporate reorganization: Auren concluded the first phase of the Corporate Reorganization (Phase 1) on May 31, 2026, upon merging Auren Participações into Auren Operações. The final stage, i.e. the merger of Auren Operations into Cesp (Phase 2), was approved by the Company on June 24, 2026, and remains subject to the implementation of precedent conditions, including regulatory approvals. Construction of Cajuína 3: the implementation of Cajuína 3, with an installed capacity of 112.1 MW, is progressing according to the planned schedule and budget, with approximately 88% of the project completed. The commissioning activities are in the final phase, with the first 6 wind turbines in test operation as of the publication date of this document. The regulatory tests and validations will continue over the coming months in preparation for full commercial operation, expected in December. During the testing period, the energy generated is settled at PLD. Curtailment compensation: on July 21, 2026, the MME published Normative Ordinance No. 140, regulating the procedures for financial compensation of wind and solar generators affected by generation cuts due to electrical reliability or external unavailability from September 2023 to November 2025. The regulation outlines the steps for implementing compensation, including expression of interest by agents, assessment and classification of cuts, and determination of amounts . The Company estimates compensation of around R$ 300 million and is evaluating the feasibility of expressing interest to participate in the mechanism by August 10, 2026, as stipulated in the Ordinance. Pró-Ética Seal: on July 1, 2026, Auren Energia received the Pró-Ética Seal, a recognition granted by the Office of the Comptroller General (CGU) to companies that stand out for adopting effective integrity and anti -corruption programs. Obtained in the Company's first participation in the assessment process, the certification reinforces Auren's commitment to high standards of ethics, governance and transparency , strengthening its ESG agenda and the generation of sustainable value for its stakeholders. Auren reports Adjusted EBITDA of R$ 859 million in 2Q26, highlighted by the start of the run-test operation at the Cajuína 3 Complex
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5 Period Overview – Operational and Financial Information Operational Highlights Generation (MWavg) 2Q26 2Q25 Change 6M26 6M25 Change Hydro 1,943.3 1,784.4 8.9% 2,002.4 2,178.4 -8.1% Wind1 1,152.5 1,279.2 -9.9% 994.8 1,137.8 -12.6% Solar1 154.6 144.3 7.2% 170.7 174.6 -2.2% Total Proprietary Assets 3,250.5 3,207.9 1.3% 3,167.9 3,490.8 -9.3% Noncontrolling Interests (NCI) in Hydroelectric Assets2 262.8 223.4 17.6% 203.5 191.4 6.3% Total Proprietary Assets and NCIs 3,513.3 3,431.3 2.4% 3,371.4 3,682.3 -8.4% Operational Highlights Average Availability 2Q26 2Q25 Change 6M26 6M25 Change Wind 92.8% 93.5% -0.7 p.p. 93.4% 92.8% 0.6 p.p. Solar 98.6% 98.6% n.a. 98.5% 97.2% 1.3 p.p. Financial Headlines (R$ mn) 2Q26 2Q25 proforma Change 6M26 6M25 proforma Change Net Revenue 3,055.5 2,885.5 5.9% 6,130.0 5,837.8 5.0% Generation 1,765.7 1,596.8 10.6% 3,468.9 3,217.8 7.8% Hydro 1,001.9 1,025.7 -2.3% 2,028.4 2,015.0 0.7% Wind 697.7 638.6 9.3% 1,284.2 1,236.8 3.8% Solar 101.6 107.3 -5.3% 235.0 237.9 -1.2% Generation eliminations (35.5) (174.8) -79.7% (78.7) (272.0) -71.1% Trading 1,999.5 1,894.2 5.6% 4,024.6 3,682.0 9.3% Eliminations (709.7) (605.4) 17.2% (1,363.4) (1,061.9) 28.4% Adjusted EBITDA3 858.9 980.6 -12.4% 1,784.8 2,185.9 -18.4% Generation 902.1 946.4 -4.7% 1,879.5 2,003.1 -6.2% Hydro 452.1 461.7 -2.1% 1,067.7 1,038.6 2.8% Wind 387.4 432.9 -10.5% 694.9 827.3 -16.0% Solar 62.5 51.9 20.5% 116.9 137.2 -14.8% Trading (17.2) 53.0 n.a. (41.0) 214.7 n.a. Holding Company and Pipeline (25.9) (18.8) 38.0% (53.7) (31.9) 68.5% Adjusted EBITDA Margin 28.1% 34.0% -5.9 p.p. 29.1% 37.4% -8.3 p.p. Net Profit (379.1) (562.9) -32.7% (980.7) (508.9) 92.7% Net Debt 18,907.5 18,748.2 0.8% 18,907.5 18,748.2 0.8% Leverage 5.3x 4.8x 0.5x 5.3x 4.8x 0.5x Note: Given the development of the Company's intersegment expenses sharing methodology, we began reporting the open generation EBITDA between hydropower sources in order to assist the market in analyzing the results and to facilitate the visualization and interpretation of the Company’s 2Q26 and 6M26 data, the figures related to the 2025 Financial Statements by segment are presented on an un audited pro-forma basis, and include the apportionment methodology applied to the Company since 01/01/2025, solely to facilitate a compar ative analysis. _________________________ 1 Includes actual generation plus the energy to be compensated due to curtailment classified as External Unavailability (REL), after reaching the allowance. For wind energy, this includes 100% of the Installed Capacity from Tucano Holding III (155 MW), a jo int venture between Auren Participações and Unipar Carbocloro S.A. (50%/50%). 2 Generation from NCI assets was weighted by Auren's indirect economic interest. 3 Adjustments detailed in the “Financial Performance” section.
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6 Message from Management The second quarter of 2026 brought an important change in the short-term price dynamics of the energy market. After a start of the year characterized by high prices, improved hydrological conditions, along with lower -than-expected demand and the incorporation of LRCAP into the pricing model, led to a significant reduction in short -term energy prices over the quarter. In the Southeast submarket, the average PLD fell from R$ 308/MWh in 1Q26 to R$ 207/MWh in 2Q26. This movement was in line with the outlook we have consistently communicated to investors and analysts since the beginning of the year, indicating that the price curve traded in the energy market included a significant premium compared to the scenarios assessed by the Company in its simulation models. The price evolution observed during the quarter thus confirmed our expectation and contributed positively to Auren's performance, given our short position for this quarter. The price reduction trend also extended into the third quarter, with successive significant declines compared to the levels observed at the beginning of the year. Although prices have receded, the market price curve still includes a significant premium for the fourth quarter, mainly reflecting the uncertainties associated with the possible impacts of El Niño on temperatures and consequently on system demand, in addition to low market liquidity and uncertainties regarding the start of the next wet season. As disclosed in our energy balance, Auren does not have significantly short exposure in 2027, even considering the effects of GSF and curtailment. Operationally, we continue to demonstrate the resilience of our portfolio in the face of challenges faced by renewable sources in the National Interconnected Grid (SIN). Modulation gains totaled R$ 70.5 million in the quarter, growing 75% compared to the s ame period last year, offs etting a significant portion of the curtailment impact, which totaled R$ 97.8 million in the period. The results reflect the combination of the Company's generation profile by hour, increased price volatility, and high PLD levels throughout the quarter. The YTD net effect of the portfolio is a negative R$ 16.3 million, resulting from a curtailment impact of R$ 184.0 million, partially offset by a positive modulation effect of R$ 167.7 million. Moreover, we observed an increase in the volume of energy associated with generation cuts compared to the same period last year. The total curtailment recorded for wind sources in the SIN reached 15.7% of potential generation in the quarter, above the levels recorded in the second quarter of 2025 and in line with the high levels observed since the beginning of this year. For solar sources, restrictions remained even more severe, reaching 25.8% in the quarter, surpassing the restriction recorded in 2Q25 and nearly 10 p.p. above the first quarter of 2026. From an operational standpoint, the quarter was marked by distinct dynamics among the different portfolio sources. The gradual improvement in hydrological conditions contributed to higher hydroelectric generation than observed in the same period of the previous year, with the system's GSF reaching 99% in the quarter. Additionally, wind assets were impacted by wind resources below the levels expected under the assets' certification, which, combined with the curtailment levels recorded, resulted in generation equivalent to 92% of P90. Nevertheless, the diversification among sources and our commercial flexibility allowed us to mitigate part of the operational challenges faced by renewable sources during the period. Despite operational resilience, the impacts of lower wind resources and lower results from the Trading Company negatively affected the quarter's outcome. We consequently recorded an adjusted EBITDA of R$ 858.9 million in 2Q26, a decrease of 12.4% compared to the same period last year. Net debt decreased by R$ 194.2 million in the quarter, while leverage ended at 2Q26 at 5.3x Net Debt/Adjusted EBITDA, slightly above the previous quarter due to the drop in EBITDA over the last 12 months. The deleveraging trajectory remains on track, with stabilization in 2026 and a decline beginning in 2027. Capex totaled R$ 139.4 million this quarter, driven by the construction of Cajuína 3 (R$ 69.5 million) and the modernization of hydroelectric plants, in addition to recurring maintenance Capex. Elsewhere, there wer e no disbursements related to regulated contract reimbursements, given the ongoing regulatory discussion about compensation mechanisms associated with curtailment. On the growth front, the Cajuína 3 project (112.1 MW) continues to progress according to the planned schedule and budget, with approximately 88% of the project completed. The commissioning activities are in the final phase, with part of the wind turbines already in operation and undergoing testing as of the publication date of this document, with the energy generated during this period being settled at PLD. The regulatory tests and validations will continue over the coming months in preparation for full commercial operation, expected in December. Cajuína 3 represents another important step in our strategy to expand the renewable portfolio. We also remain attentive to selective growth opportunities that offer returns compatible with our capital allocation discipline. We are therefore closely monitoring the development of the battery auction schedule d for December 2026. The project registration phase concluded in July, while the publication of the project roll-out margins is expected in September. On the regulatory front, we have been actively participating in discussions about curtailment with the government, ANEEL, and other industry entities. Our focus remains on the regulation of compensations already approved by law, which would mitigate the negative effects of curtailment and create a more favorable environment for the expansion of renewable energy supply in Brazil. On July 21, the MME published an Ordinance containing the Commitment Agreement for financial compensation to generators affected by cuts from September 2023 to November 2025. As part of the process, in the coming days, interested parties must express their interest in signing the Agreement, follow ed by the procedures for
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7 determining, validating, and formalizing the compensation amounts, which are expected to continue into next year. In light of this, we continue to assess the impacts o f the regulation and conduct the necessary internal analysis and approval processes for potential adherence to the Agreement. We view the Ordinance as an important advancement, but the definition of the curtailment compensation rule from December 2025 remains uncertain, depending on regulation from ANEEL. While the publication of the Ordinance represents a significant advancement in addressing the impacts already observed, we continue to advocate for the construction of a structural and definitive regulatory solution for curtailment that can restore predictability and stability to a segment crucial for the expansion and sustainability of the Brazilian Electric Sector. We have also made progress on a key strategic front with the completion of the first phase of the corporate reorganization, which involved the merger of Auren Participações into Auren Operações. We also advanced to stage two of the process (the merger of A uren Operações into C ESP), which has been approved by the Company and is currently subject to fulfilling precedent conditions, including regulatory approvals. This initiative reinforces our commitment to consolidating a simpler and more efficient corporate structure, concentrating hydroelectric assets within a single entity (C ESP), reducing the number of publicly traded subsidiaries, and enhancing cash and debt management efficiency. Despite the sectoral challenges faced, we have consistently advanced our strategic priorities. We believe that the initiatives implemented throughout the half strengthen Auren to seize growth opportunities, enhance its operational efficiency, and continue generating sustainable value for its shareholders and other stakeholders. Fabio Zanfelice CEO Mateus Ferreira Chief Financial and Investor Relations Officer
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8 Electricity Market Following a rainy season with significantly below Long Term Average (LTA) Streamflow Energy (ENA) in most of the country (ENA from October 2025 to January 2026 was only 67% of LTA, the 3rd worst in history), the situation reversed in February, leading to a consistent recovery of the Southeast-Midwest (SE/MW), Northeast (NE), and North (N) subsystem reservoirs, with only the South (S) subsystem remaining at low storage levels. However, from May, with the onset of the rainy season in the south of the country, abundant rainfall was observed in most of the river basins in th at region, resulting in an ENA of 112% LTA, significantly contributing to the recovery of the subsystem's reservoirs. Over the month of May, there was a 30 p.p. increase in reservoir levels in the Southern subsystem, after reaching the minimum operational volume of 30% in April. In the Southeast/Midwest (SE/ MW) submarket, the average ENA reached 87% in 2Q26, notably in June, which recorded an ENA of 94% LTA. These conditions allowed for maintaining comfortable storage levels in the SIN. The combination of more favorable atmospheric wind currents and the gradual warming of the Pacific Ocean contributed to concentrating rainfall in the South and SE/ MW during 2Q26, while the Northeast and North regions experienced drier conditions than usual for the period. The ENA of the National Interconnected Grid (SIN) in 2Q26 was 4 p.p. higher than the same period the previous year, hitting 82% LTA, compared to 78% LTA seen in 2Q25. Compared to the previous quarter (79% LTA in 1Q26), there was a 3 p.p. increase. Gross Monthly Natural Streamflow (ENA) in the SIN (GWavg) Source: ONS Temperatures in the Southeast/Midwest remained below the climatological average for the fifth consecutive quarter, particularly in June, when deviations were more pronounced. There was no significant thermal contrast compared to the previous year, as 2Q25 also had below-average temperatures. Despite the demand in the SIN growing by 3.2% compared to 2Q25, temperature behavior continued to impact energy consumption in the system. As a result, the global load recorded reached an average of 81.8 GW in 2Q26, about 2% below ONS's projection (PLAN 2026-301). Given the improved hydrological conditions in the South, unexpected rainfall in the Southeast, and reduced load due to lower temperatures, reservoir levels remained stable in 2Q26, mostly between 70% and 72% of maximum capacity throughout the quarter. As a result, 2Q26 ended with 71% storage, which is 13 p.p. above the ten-year average and 1 p.p. higher than at the end of 2Q25. SIN Reservoir Levels (% Maximum Energy Stored) Source: ONS Regarding MRE hydroelectric generat ion, 2Q26 recorded 45 GWavg, about 1 GWavg higher than 2Q25, reflecting more favorable hydrological conditions compared to the same period the previous year. Meanwhile, the GSF observed in 2Q26 (99%) gained 3 p.p. on 2Q25 (96%), of which 2 p.p. is due to higher hydroelectric generation and 1 p.p. from lower firm _________________________ 1 Annual Energy Operation Planning Report 2026-2030 publication in December 2025. Gross ENA/ LTA Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2Q 6M 2025 98% 90% 66% 75% 71% 92% 83% 77% 75% 67% 71% 67% 78% 82% 2026 63% 82% 90% 82% 84% 81% - - - - - - 82% 80%
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9 energy allocation by MRE participants in the second quarter (45 GWavg in 2Q26 vs. 46 GWavg in 2Q25), as illustrated in the chart below. Hydro Displacement (% GSF) Source: CCEE Solar generation, including both centralized plants and distributed micro and mini generation (MMGD), continued increasing its share in meeting SIN load. It contributed 10.1 GWavg (approximately 13% of load) in 2Q26, compared to 9. 4 GWavg in 2Q25 (12% of load). Moreover, wind generation reduced its share in load supply by 1 GWavg ( -1 p.p.) compared to 2Q25, in response to reduced wind resource between quarters (14.4 GWavg in 2Q26 vs. 14.9 GWavg in 2Q25) and higher generation curtailment. Hydroelectric generation remained stable in meeting the load, accounting for 60% in both 2Q26 and 2Q25. A similar pattern was observed in thermal generation, maintaining an 11% share in meeting the load in both periods mentioned. Energy Balance (SIN) – Contribution by Source to Load Supply (GWavg) Source: ONS The PLD in the Southeast/Midwest (SE/MW) submarket averaged R$ 207/MWh in the quarter, with intraday volatility of 45%, a significant decrease compared to an average PLD of R$ 216/MWh in 2Q25 and intraday volatility of 42%. Moreover, in the Northeast (NE) submarket, because of lower wind resources, the average PLD was higher than recorded the previous year (R$ 164/MWh in 2Q26 vs. R$ 154/MWh in 2Q25), thus closing the gap with SE/ MW (-R$ 43/MWh in 2Q26 vs. -R$ 62/MWh in 2Q25). In the Southern submarket, the gap compared to SE/ MW was greater than last year (R$ 24/MWh in 2Q26 vs. R$ 8/MWh in 2Q25). As observed in previous quarters, the most significant price variations throughout the day continued to be concentrated between late afterno on and early evening. The intraday price volatility in the SE/ MW submarket of 45% in the quarter shows an increase compared to the 42% observed in 2Q25, primarily due to the increase in installed MMGD capacity and the increase in exchange limits, directly impacting the daily net load curve, which has been intensifying over the years. In line with the changing hydrological conditions observed over the first six months of 2026, the PLD showed a downward trend compared to the first and second quarters. After starting the year at a high level, with an average PLD of R$ 308/MWh in the SE/ MW submarket in 1Q26, the price fell in 2Q26, reflecting an improvement in the system's supply conditions,
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10 driven by the recovery of inflows and the load reduction in the SIN. Despite the decline in the average price, intraday volatility remained high, in line with the greater variability of prices throughout the day. Average PLD and Volatility by Submarket (R$/MWh) PLD by Submarket (R$/MWh) Intraday Volatility (%) 2Q26 2Q25 Change 6M26 6M25 Change 2Q26 2Q25 Change 6M26 6M25 Change SE/MW 206.6 216.4 -4.5% 257.1 189.5 35.7% 45% 42% 3 p.p. 45% 32% 13 p.p. South 230.8 224.3 2.9% 294.0 194.4 51.2% 34% 39% -6 p.p. 32% 30% 2 p.p. Northeast 163.5 154.1 6.1% 224.8 106.8 110.5% 43% 34% 9 p.p. 46% 24% 22 p.p. North 165.2 154.6 6.9% 225.9 107.0 111.1% 42% 33% 9 p.p. 45% 24% 21 p.p. Source: CCEE Finally, based on ONS data, 2Q26 showed an increase in generation curtailments compared to 2Q25. For wind generation in the SIN, total curtail ment in 2Q26 was 15.7% (2.2 GWavg), significantly above the 11.7% (1.7 GWavg) recorded in 2Q25 and the 14.9% (1.6 GWavg) in the first quarter of 2026. For solar sources, the curtailment was 25.8% (1.3 GWavg) for the quarter, surpassing the 22.7% (1.0 GWavg) from 2Q25 and significantly higher compared to 16.2% (0.8 GWavg) in the first quarter of 2026. Curtailments for electrical reasons, eligible for compensation after reaching the allowance threshold, accounted for 17% for wind and 11% for solar curtailment s, above the amount observed in 2Q25, when curtailments classified as electrical reasons stood at 11% and 7% respectively. Percentage Share of Curtailments by Reason (GWavg, % of Total) The dynamics outlined above highlight both the challenges during the quarter, especially those imposed by curtailment, and the opportunities for securing modulation gains under the current PLD dynamics.
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11 Operational Performance In this section, we present the Company's operational performance, which reflects its ability to adapt to different weather and market conditions and demonstrates the resilience of Auren's portfolio. Installed Capacity and Generation1 by Source Source Installed Capacity (MW) Firm Energy (MWavg) Generation1 (MWavg) 2Q26 2Q25 Change 6M26 6M25 Change Hydro2 4,198.4 2,074.6 1,943.3 1,784.4 8.9% 2,002.4 2,178.4 -8.1% Wind3 3,100.4 1,499.0 1,152.5 1,279.2 -9.9% 994.8 1,137.8 -12.6% Solar 876.4 238.2 154.6 144.3 7.2% 170.7 174.6 -2.2% Total Proprietary Assets 8,175.3 3,811.8 3,250.5 3,207.9 1.3% 3,167.9 3,490.8 -9.3% Noncontrolling Interests (NCI)4 547.5 265.3 262.8 223.4 17.6% 203.5 191.4 6.3% Total Proprietary Assets and NCIs 8,722.8 4,077.2 3,513.3 3,431.3 2.4% 3,371.4 3,682.3 -8.4% Hydro Auren’s proprietary hydropower assets generated 1.9 GWavg in the second quarter of 2026, representing an 8.9% increase compared to the same period of the previous year. Despite the progress, energy production was 6. 2% below the firm energy for the quarter, reflecting seasonality and less favorable hydrological conditions during this period. In the first six months of the year, production reached 2.0 GW average, 8.1% lower compared to the same period last year. Thus, despite the improvement seen in the second quarter, accumulated hydro dispatches in 2026 remain lower than the previous year, indicating a more restrictive operation throughout the half. The chart below shows hydro plant generation since the beginning of the year: Energy Generation and Firm Energy Values (MWavg)² In 2Q26, the Verified Availability Index (IDv60) remained above ANEEL's benchmark values at the main hydroelectric plants in the portfolio —Porto Primavera and Água Vermelha – which jointly represent 70.2% of the Company's installed hydroelectric capacity. For the plants where the indicators remain below the benchmark thresholds – equal to 24.1% of Auren's hydro capacity—the performance primarily reflects isolated events from previous periods, such as major scheduled maintenance activities or specific operational incidents. Additionally, the Company conducted a structured diagnostic of the assets, focusing on identifying opportunities to strengthen operational reliability and mitigate potential risks to future performance. The results supported the revision and _________________________ 1 For wind and solar sources, this includes actual generation plus the energy to be compensated due to curtailment classified a s External Unavailability (“REL”), after reaching the allowance. 2 Includes generation from the Mogi-Guaçu, São José and São Joaquim SHPs. Does not include Paraibuna HPP. 3 For wind energy, this includes 50% of the Installed Capacity from Tucano Holding III, a joint venture between Auren Participações and Unipar Carbocloro S.A. (50%/50%). The asset has 155 MW of total Installed Capacity, of which 77.5 MW reflects Auren's own ership stake. For the operational data of the joint venture, a 100% ownership interest is assumed. 4 The data on installed capacity and generation were weighted according to Auren’s indirect economic interest in the hydroelect ric assets.
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12 rescheduling of the multi -year maintenance plan, directing investments and interventions towards the most impacted equipment. This approach aims to enhance asset reliability, preserve operational availability, and sustain performance indicator growth in future regulatory cycles. Wind The performance of wind assets during the quarter reflected a combination of increased curtailment levels and lower-than- expected resources than the asset certification. Total generation¹ reached 1,152.5 MWavg in 2Q26, which is 84.3% of percentile 50 (P50) and 92.0% of percentile 90 (P90), while potential generation² reached 94.8% and 103.5% of P50 and P90, respectively. Generation was 9.9% lower than the same period last year, also reflecting the effects influencing the quarter's performance related to certification. Compared to 1Q26, total generation in 2Q26 was 38.0% higher, mainly driven by the seasonality eff ect of the source (expected generation in Q2 is 26% higher than in Q1), while the impact of curtailment remained at similar levels between the second and first quarter of 2026. The chart below presents the monthly performance of (i) total generation, consisting of actual energy output plus the reimbursable share of energy not produced due to electricity curtailments; (ii) potential generation; and (iii) the 50 th and 90th percentile certification benchmark values. Wind Assets – Energy Generation and Certified Values for P50 and P90 (MWavg) Due to tri-annual shutdowns at Ventos do Piauí I substations in April and maintenance at Tucano, Cajuína, and Mandacaru in May, wind asset availability reached 92.8% in 2Q26, a reduction of 0.7 p.p. compared to the same period in 2025. Over the half, there was a 0.6 p.p. improvement compared to the results observed in 6M25. These results highlight the maturity in the process of recovering operational performance for the incorporated clusters. Even though availability was impacted by scheduled outages d uring the period, part of this effect is compensable, as stipulated in the minimum availability contractual obligations of the Full Scope Agreement (FSA) maintenance contracts with manufacturers where wind turbine maintenance is fully outsourced. _________________________ 1 Total generation = energy produced + portion of energy not generated due to electrical constraint curtailment. 2 Potential generation = energy produced + portion of energy not produced due to various types of restrictions imposed by the N ational System Operator (ONS). MWavg Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2Q Total Generation 20251 684.7 1,250.8 1,073.9 984.9 1,404.3 1,444.1 1,457.6 1,493.4 1,583.6 1,426.5 1,105.7 1,000.1 1,279.2 Total Generation 20261 1,063.4 712.3 718.1 947.1 1,235.4 1,272.3 - - - - - - 1,152.5 Potential Generation 20252 727.9 1,338.7 1,156.8 1,035.4 1,574.7 1,626.6 1,722.4 1,835.1 2,022.9 1,994.2 1,410.9 1,171.0 1,414.0 Potential Generation 20262 1,298.9 765.5 802.7 1,075.9 1,389.2 1,422.1 - - - - - - 1,296.8 2Q26 Deviation from Certification (%) P90: -8.0% P50: -15.7%
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13 Wind Portfolio - Consolidated Average Availability Average Availability (Consolidated) 1Q 2Q 3Q 4Q 6M 2025 92.0% 93.5% 94.8% 94.2% 92.8% 2026 94.0% 92.8% - - 93.4% Considering total generation, the wind portfolio reached 84.3% of P50 in 2Q26, as shown in the graph below. As mentioned earlier, performance was mainly impacted by the curtailment observed within the quarter, which reduced expected generation by 13.1 p.p., of which 10.5 p.p. are related to the non-reimbursable portion and 2.6 p.p. to the cuts classified as reimbursable REL. The remaining difference compared to certification is primarily explained by the behavior of the wind resource during the period, which independently reduced generation by 4.4%. Wind Portfolio – Consolidated Generation Performance in 2Q26 (P50 indexed to 100)1 Wind Portfolio – Consolidated Generation Performance in 6M26 (P50 indexed to 100)18¹1 ²8 Solar Solar asset energy production plus the reimbursable portion of generation curtailment classified as External Unavailability (REL), was 154.6 MWavg in 2Q26. In the quarter, total generation represented 67.8% of percentile 50 (P50) and 74.0% of percentile 90 (P90) as defined by the certification for farm generation, whereas potential generation2 reached 95.2% and 103.9% of P50 and P90, respectively. Compared to 2Q25, this quarter's generation was 7.2% higher, mainly due to better resources, while the curtailment remained at similar levels when considering the reimbursable and non -reimbursable portions. Quarterly generation was 17.3% lower than in 1Q26, primarily due to seasonal effects (expected generation in Q2 is 12% lower than in Q1), combined with a more negative deviation in curtailment considering reimbursable and non-reimbursable portions. _________________________ 1 The curtailment figures in this subsection refer to the Company’s internal data and differ from the figures presented in the “Curtailment Impact and Modulation Gains” section, which are based on data published by ONS. 2 Potential generation = energy produced + portion of energy not produced due to various types of restrictions imposed by the ONS.
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14 The chart below presents the monthly comparison of: (i) total generation – consisting of actual energy output plus the share of energy not produced due to REL restrictions (compensable); (ii) potential generation – representing actual generation plus the share of energy not produced d ue to various ONS -imposed restrictions; and (iii) the 50 th and 90 th percentile certification values. Solar Assets – Energy Generation and Certified Values for P50 and P90 (MWavg) Solar asset availability reached 98.6% in 2Q26, in line with the same period of 2025 and a slight advance relative to 1Q26. In the accumulated first half, it reached an average availability of 98.5%, exceeding the accumulated first half of 2025 by 1.3 p.p., as presented in the table below. Solar Portfolio - Consolidated Average Availability Average Availability of Assets 1Q 2Q 3Q 4Q 6M 2025 95.9% 98.5% 99.0% 98.8% 97.2% 2026 98.4% 98.6% - - 98.5% As shown in the chart below, the solar portfolio's production reached 67.8% of P50 in 2Q26. The main impact on the solar assets' performance during the second quarter is related to curtailment, which reduced the expected generation by 29.7 p.p, of which 27.4 p.p. are related to the non-reimbursable portion and 2.3 p.p. related to reimbursable REL curtailment. _________________________ 1 Total generation = energy produced + portion of energy not generated due to electrical constraint curtailment. 2 Potential generation = energy produced + portion of energy not produced due to various types of restrictions imposed by the N ational System Operator (ONS). 144 175 155 171 217 224 209 223 228 243 206 185 169 172 148 145 254 214 226 239 207 205 0 50 100 150 200 250 300 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2Q 6M 2025 Total Generation Potential Generation P90 P50 MWavg Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2Q Total Generation 20251 198.3 227.2 192.3 157.8 143.6 131.5 155.7 162.4 173.2 164.5 175.8 194.3 144.3 Total Generation 20261 206.2 184.9 169.5 171.6 147.8 144.8 - - - - - - 154.6 Potential Generation 20252 227.7 256.1 242.3 203.9 212.1 206.4 218.6 255.8 270.1 257.4 240.2 245.9 207.5 Potential Generation 20262 254.1 214.0 225.9 238.9 207.3 205.3 - - - - - - 217.1 Deviation from Certification (%) P90: -26.0% P50: -32.2%
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15 Solar Portfolio – Consolidated Generation Performance in 2Q26 (P50 indexed to 100)1 Solar Portfolio – Consolidated Generation Performance in 6M26 (P50 indexed to 100)¹ Curtailment and Modulation Gains Important: the curtailment data in this section references figures published by the ONS and differ from those in the "Wind and Solar" sections, which rely on the Company’s internal estimates. The table below presents the curtailment percentages for the wind and solar sources in Auren’s portfolio, calculated as a percentage of Potential Generation and of the 50 th percentile (P50), and SIN curtailment. We are also presenting the financial impact of curtailment for the Company and the benefits of modulation gains captured by its diversified asset portfolio and its generation profile against short-term price (PLD) variations, since most energy sales contracts in the Free Contracting Environment (ACL) have a flat profile. In financial terms, the impact of curtailment on the asset portfolio, excluding the compensable portion of REL curtailments after the allowance had been met, was R$ 98 million, a 13.5% increase compared to 1Q26. R$ 5 million of this total denotes the non-compensable portion (before the hours allowance is reached) of REL-classified curtailments, R$ 14 million denotes reliability-based curtailments and R$ 79 million energy curtailments. Modulation gains totaled R$ 70.5 million in 2Q26. Although lower than those recorded in 1Q26, due to a decrease in price levels observed throughout the quarter, these gains remained significantly above 2Q25 and offset most of the negative impact of curtailment, resulting in a negative net impact of R$ 27.3 million on the Company's results. In the first six months of the year, the net modulation effect was R$ 16.3 million, as a result of a total curtailment impact of R$ 184.0 million with R$ 167.7 million in modulation over the period. _________________________ 1 The curtailment figures in this subsection refer to the Company’s internal data and differ from the figures presented in the “Curtailment Impact and Modulation Gains” section, which are based on data published by ONS.
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16 Curtailment and Modulation Gains 2Q25 3Q25 4Q25 1Q26 2Q26 Wind Solar Wind Solar Wind Solar Wind Solar Wind Solar SIN Curtailment1 (%) 11.7% 22.7% 20.6% 33.2% 23.1% 23.9% 14.9% 16.2% 15.7% 25.8% SIN Curtailment2 ex-REL (%) 10.4% 21.1% 19.7% 31.3% 22.7% 22.4% 11.5% 14.5% 13.1% 23.1% Auren Curtailment2 (%) 9.0% 25.7% 18.3% 27.4% 22.3% 23.2% 13.4% 16.3% 12.9% 26.0% Effective Auren Generation3 (% of P50) 93.5% 62.8% 79.9% 65.4% 78.3% 69.1% 77.2% 72.3% 84.3% 67.8% Auren Curtailment by Source4 (R$ million) 56.7 19.1 173.2 22.4 184.2 23.3 69.9 15.6 77.8 20.1 Auren Consolidated Curtailment5 (R$ million) 75.8 195.5 207.5 86.2 97.8 (-) Modulation gains (R$ million) 40.4 65.6 70.4 97.2 70.5 (=) Curtailment Net of Modulation5 (R$ million) 35.4 130.0 137.0 -11.0 27.3 Energy Balance The Company's Consolidated Power Balance presents the contracting profile in the Regulated Contracting Environment (ACR) and Free Contracting Environment (ACL), the contracting level of the Generation and Consolidated portfolio, including the Trading portfolio. We also detail the average selling price of Generation. Consolidated Energy Balance 2Q26 was marked by intense activity in the Trading, trading more than 800 MWavg5 including energy purchases and sales throughout 2026. Compared to the Consolidated Balance Sheet for 1Q26, the Company marginally decreased its long position for the 2027-2030 period, through the contracting of 13 MW average in the Trading segment. Energy Balance - Generation Segment 2Q26 was characterized by the execution of short-term operations aimed at adjusting the seasonality of exposures, without significant impacts on the long-term portfolio's transaction level. The main movements made are as follows: o Execution of an 81 MWavg conventional energy swap in 2027, with the Trading Division, to adjust the seasonality of exposures resulting from the portfolio’s generation profile. The aim of this operation was to prevent a significant position mismatch between quarters considering the effects of GSF and curtailment. o Long-term sales contract transfer of 150 MWavg from the Generation segment to the Trading segment, as detailed in the 2Q25 Release. This movement had a positive impact on the Generation segment’s EBITDA of R$ 15.9 million in 2Q26, totaling an impact of R$ 92 million in 2026 and R$ 62 million in 2027. This impact is EBITDA -neutral at the consolidated level. _________________________ 1 SIN Curtailment (%) = (Energy-Based Curtailment Energético + Reliability-Based Curtailment) / Potential Generation. Potential Generation corresponds to actual energy generation plus the energy not produced due to all types of ONS -imposed restrictions. 2 Auren Curtailment (%) (Energy -Based Curtailment + Reliability -Based Curtailment + Non -reimbursable Power Curtailment) / Potential Generation. Potential Generation correspo nds to actual energy generation plus the energy not produced due to all types of ONS -imposed restrictions. 3 Effective Auren Generation (% of P50) = (Effective Generation + Reimbursable Power Curtailment) / P50 , in line with the values reported in the Wind and Solar sections. 4 Auren Curtailment (R$ million) = Energy-Based Curtailment + Reliability-Based Curtailment + Non-reimbursable Power Curtailment 5 On an annualized basis
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17 Auren Generation Portfolio Energy Balance Volume (MWavg) 2026 2027 2028 2029 2030 2031 Own Funds (A) 3,678 3,777 3,777 3,777 3,777 3,777 Firm Energy - Hydroelectric1 1,990 2,027 2,027 2,027 2,027 2,027 Firm Energy - Wind2,3 1,455 1,516 1,516 1,516 1,516 1,516 Solar Firm Energy 234 234 234 234 234 234 Purchases for Resale (B) 914 596 485 320 320 314 Conventional 435 280 171 6 6 0 Incentivized 479 317 314 314 314 314 Total Funds (C = A+B) 4,592 4,373 4,262 4,097 4,097 4,091 Sales in ACR (D) 1,086 1,086 1,187 1,081 1,081 1,080 Hydro 235 235 336 230 230 229 Wind 786 786 786 786 786 786 Solar 65 65 65 65 65 65 Sales in ACL (E) 3,061 2,745 2,487 1,982 1,720 1,444 Hydro4 2,253 1,930 1,672 1,167 905 670 Wind 654 671 671 671 671 671 Solar 154 144 144 144 144 102 Total Sales (F = D+E) 4,147 3,831 3,674 3,063 2,801 2,524 Generation Balance (C - F) 445 542 588 1,034 1,296 1,567 Conventional 318 517 476 899 1,148 1,380 Incentivized 128 25 113 135 148 187 Prices (R$/MWh) 2026 2027 2028 2029 2030 2031 Average Sale Price4 196 212 210 216 222 227 ACR 277 285 283 286 286 286 Hydro 313 321 304 325 325 325 Wind 260 268 268 268 268 268 Solar 355 367 367 367 367 367 ACL 167 183 176 179 182 184 Hydro 151 170 158 157 158 160 Wind 210 216 214 210 211 205 Solar5 218 208 204 203 200 201 Average Purchase Price6 196 207 193 187 187 175 Conventional 181 215 190 145 145 0 Incentivized 210 201 195 188 188 175 _________________________ 1 Figures include: (a) Firm Energy of proprietary assets net of the MRE adjustmen t factor (GSF) for the realized period through March 31, 2026 only - assume GSF equals 1 for other periods; (b) exclude energy from the Paraibuna HPP; (c) apply a 3% loss rate for assets connected to the main grid; (d) exposure of period realized until Jun e 30, 2026 fully settled at PLD and (e) firm energy subject to GSF totals 1,782 through 2028, with protection for 230 MW from the Porto Primavera HPP - in return, the Company is paying a monthly premium of R$ 17.32/MWh. Base date: January 01, 2026. 2 Includes 50% of the firm energy from Tucano Holding III, a joint venture between Auren Participações and Unipar Carbocloro S.A. This also affects the average purchase and resale prices in the respective periods. 3 Assumes commercial operations start at the Cajuína 3 cluster in January 2027, adding 63 MWavg of projected firm energy. 4 The hydro segment’s ACL sales include a portion of incentivized energy sales, as Auren Operações is classified under the hydr o segment but also executes contracts from wind assets. 5 The equivalent price of the lease-based self-generation contract is net of PIS, COFINS and ISS. 6 Figures are net of PIS and COFINS. They include both ACR and ACL in the average selling price, and only ACL in the average pu rchase price for conventional and incentivized energy. Base date: July 01, 2026. Exchange rate: R$ 5.17/USD. The Company’s energy contracts are mostly indexed to the National Broad Consumer Prices Index (IPCA).
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18 Energy Balance - Trading Segment The table below presents the Company's Trading Energy Balance, including sales margins for 2026 and 2027. The figures reflect volumes traded through the energy trading firms Auren Comercializadora, Tietê Integra (formerly AES Tietê Integra), CESP Comercializadora and Esfera. Energy Balance of Auren's Trading Portfolio Volume (MWavg) 2026 2027 2028 2029 2030 2031 Purchases (A) 5,081 2,806 2,089 1,277 916 627 Sales1 (B) 5,177 2,923 2,121 1,230 962 709 Contractual Margin2 (R$/MWh) 7.2 9.2 - - - - Trading Balance (A - B) (96) (117) (32) 47 (47) (82) Auren Consolidated Balance3 350 425 556 1,081 1,249 1,485 When analyzing the trading portfolio's contractual margin, it is important to consider the calculation as indicated in our Modeling Guide. The 96 MWavg short position annualized for 2026, for example, will be marked to market prices for the second quarter. In 2Q26, portfolio management was marked by the movements below: a) Reduction of the short exposure for 2026 by 29 MWavg while preserving the contractual margin for 2026 (R$ 7.2/MWh), capitalizing on the trend of falling spot energy prices. b) Net sale of 13 MWavg of energy to end consumers for the 2027-2031 period, due to an increase in energy prices for the period, resulting in a contractual margin increase of R$ 0.7/MWh for 2027. c) Long-term sales contract transfer of 150 MWavg from the Generation segment to the Trading segment, as detailed in the 2Q25 Release. This movement had a negative impact on the Trading segment EBITDA of R$ 15.9 million in 2Q26, totaling an impact of R$ 92 million in 2026 and R$ 62 million in 2027. This impact is EBITDA-neutral at the consolidated level. Excluding this contract assignment, the trading margin would have been approximately R$ 9.3/MWh in 2026 and R$ 11.7/MWh in 2027, over and above the reported R$ 7.2/MWh and R$ 9.2/MWh. _________________________ 1 Includes formal contracts in ACR and ACL. 2 The contractual margin is calculated as the difference between revenue and expenses under formal contracts, divided by the sales volume. It does not include the valuation of future exposure. Base date: July 01, 2026. Exchange rate: R$ 5.17/USD (R$/USD). 3 The Consolidated Energy Balance embraces both segments (Generation and Trading).
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19 Energy Balance of Noncontrolling Interests (NCI) Power balance and financial information are presented on a consolidated basis for the CBA Energia, Pollarix and Pinheiro Machado holdings, in which the Company holds noncontrolling interests and whose balances are recognized under the equity method in the Company’s consolidated financial statements. Dividends from these interests are recognized in the Company’s Adjusted EBITDA. Energy Balance of Hydro Assets with Noncontrolling Interests1 Volume (MWavg) 2026 2027 2028 2029 2030 Firm Energy of assets (a) 250 256 256 244 244 Purchases (b) 53 5 4 4 4 Resource (c) = (a)+(b) 303 261 260 248 248 Sales in ACL (d) 279 256 256 244 244 Requisites (e) 279 256 256 244 244 Energy Balance (f) = (c) – (e) 24 5 4 4 4 Analyzing the 2Q26 Power Balance reveals a 1 MWavg impact on the assets’ Firm Energy for 2026, resulting from the impact of the GSF realized during the period. The Power Balance for Noncontrolling Interests only includes energy purchase and sale transactions with the market, excluding intercompany contracts between hydropower assets and the subholdings (Pollarix, Pinheiro Machado and CBA Energia). Renegotiated Use of Public Asset (UBP) In June 2026, the Baesa (UHE Barra Grande) and Enercan (UHE Campos Novos) projects, in which Auren holds an indirect interest through CBA Energia and Pollarix, completed their acceptance of the renegotiation mechanism for the Use of Public Asset (UBP), as outlined in Law No. 15.235/2025. The operation facilitates the advance settlement of the remaining UBP balance, resulting in value capture for the assets and generating significant economic and financial benefits. The positive impacts from the renegotiation are expected to be reflected in the projects' results over the coming quarters. _________________________ 1 Notes: (i) Firm energy of assets net of the MRE (GSF) adjustment applied; (ii) Firm energy net of internal and national grid losses (3%); (iii) Firm energy subject to hydrological risk (GSF); (iv) Reflects resources (firm energy and purchase contracts) and obligations (sales) proportional to Auren’s equity interest in the NCI assets (Pollarix, CBA Energia Participações and Pinheiro Machado).
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20 Consolidated Financial Performance In addition to the Generation and Trading segments, the results presented here include the holding & pipeline segment and intersegment eliminations. The share of profit (loss) of equity -accounted investees includes assets not controlled by the Company: (i) Auren’s NCIs in hydropower assets, detailed in the section “Auren’s NCIs”, in the chapter Power Balance, plus (ii) Auren’s 50% interest in the joint venture between the Tucano wind cluster and Unipar Carbocloro S.A. (Tucano Holding III), which recorded EBITDA 1 of R$ 9.0 million in 2Q26. For further information, see Note 10 to the Quarterly Financia l Information. Results for the period R$ million 2Q26 2Q25 Change 6M26 6M25 Change Gross Revenue 3,481.1 3,336.9 4.3% 6,980.7 6,740.8 3.6% Deductions on Gross Revenue 425.6 451.3 -5.7% 850.7 903.0 -5.8% Net Revenue 3,055.5 2,885.5 5.9% 6,130.0 5,837.832 5.0% Power Purchase Cost (1,790.5) (1,542.3) 16.1% (3,567.0) (2,873.3) 24.1% Electricity grid usage charges (185.6) (176.7) 5.1% (365.3) (357.2) 2.3% Net Margin 1,079.4 1,166.5 -7.5% 2,197.7 2,607.4 -15.7% Net Margin 35.3% 40.4% -5.1 p.p. 35.9% 44.7% -8.8 p.p. Costs and Expenses (PMSO) (316.5) (291.5) 8.6% (628.1) (593.5) 5.8% Other Operating Income (OOI) 47.9 (358.0) n.a. (458.7) (119.4) 284.2% EBITDA 810.8 517.0 56.8% 1,110.9 1,894.5 -41.4% Mark-to-Market Adjustment of Energy Futures (ORO) (96.7) 354.6 n.a. 409.3 125.4 226.4% NCI Dividends 110.3 95.4 15.6% 199.6 153.7 29.8% Non-Recurring Items Related to Growth Initiatives (PMSO) (0.1) 11.0 n.a. (0.1) 16.5 n.a. Accrual/(Reversal) of Provision for Litigation and Write-off of Judicial Deposits (ORO) 34.7 (0.5) n.a. 65.2 (23.7) n.a. Write-off of PPE and intangible assets (ORO) - - n.a. - 16.4 n.a. Other Adjustments - 3.1 n.a. - 3.1 n.a. Adjusted EBITDA 858.9 980.6 -12.4% 1,784.8 2,185.9 -18.4% Adjusted EBITDA Margin 28.1% 34.0% -5.9 p.p. 29.1% 37.4% -8.3 p.p. Depreciation and Amortization (465.4) (521.7) -10.8% (932.3) (979.9) -4.9% Share of profit (loss) of equity- accounted investees 39.6 14.8 168.3% 111.1 86.9 27.8% Net Finance Income (Loss) (732.1) (644.5) 13.6% (1,322.0) (1,376.6) -4.0% EBT (347.2) (634.5) -45.3% (1,032.3) (375.1) n.a. Taxes (IR/CSLL) (31.8) 71.7 n.a. 51.6 (133.7) n.a. Net Profit (379.1) (562.9) -32.7% (980.7) (508.9) 92.7% Net Margin Net Margin—Net Revenue less Energy Purchase Costs and Sector Charges —totaled R$ 1,079.4 million in 2Q26, a 7.5% decrease (-R$ 87.1 million) compared to 2Q25 (R$ 1,166.5 million). The effects that influenced the result were concentrated mainly in the Trad ing, especially the lower sales margin (R$ 47.0 million). The main effects in the Generation portfolio were: (i) a 9.9% reduction in the volume generated by wind farms due to lower resources (R$ 44.3 million) and curtailment (R$ 21.1 million), (ii) lower prices of PPAs in the free market for hydroelectric plants this quarter (R$ 41.8 million), and (iii) higher Sectoral Charges (R$ 9.3 million), partially offset by higher modulation gains (R$ 30.1 million), monetary restatement of the PPAs for wind and solar farms (R$ 35.7 million), and a 7.2% increase in solar generation (R$ 3.3 million). _________________________ 1 Including Auren Participações’ proportional interest in the joint venture.
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21 Compared to the Net Margin of 1Q26 (R$ 1,118.3 million), there was a 3.5% reduction (R$ 38.9 million) in 2Q26, mainly explained by lower modulation gains (R$ 26.7 million) and a greater impact of curtailment (R$ 15.7 million), in addition to the seasonal effects on assets. Costs and Expenses (PMSO) Operating Costs and Expenses and General and Administrative Expenses (PMSO), inclu ding growth initiatives and non - recurring items, totaled R$ 316.5 million in 2Q26, an increase of R$ 25.0 million (8.6%) compared to the same quarter of the previous year (R$ 291.5 million), but in line with the amount observed in 1Q26 (R$ 313.5 million). Costs and Expenses (Consolidated PMSO) R$ million 2Q26 2Q25 Change 6M26 6M25 Change Personnel (P) 125.3 112.0 11.9% 236.4 227.1 4.1% Materials and Outsourced Services (MS) 138.1 138.6 -0.3% 284.5 284.2 0.1% Other (O) 53.1 40.9 29.7% 107.3 82.1 30.6% PMSO 316.5 291.5 8.6% 628.1 593.5 5.8% The change between periods is explained by: a) Personnel (P): personnel costs and expenses totaled R$ 125.3 million in 2Q26, a nominal increase of 11.9% compared to the same period in 2025 (R$ 112.0 million), mainly due to inflation during the period (R$ 5.5 million) and new Long-Term Incentive (ILP) grants to the Company's management (R$ 4.8 million). Compared to 1Q26 (R$ 111.0 million), there was an increase in labor expenses including provision for variable compensation, new ILP grants, and severance payments. b) Third-Party Materials and Services (MS): material and service costs totaled R$ 138.1 million in 2Q26, in line with the amount recorded in 2Q25 (R$ 138.6 million). The variation reflects the increased expenses in operating and maintenance contracts for wind assets due to contractually scheduled sc aling (R$ 3.1 million), offset by a reduction in outsourced services. There was a reduction of R$ 10.2 million on 1Q26 (R$ 148.3 million), mainly due to a one -time expense related to the end of the contractual cycle of service providers for operating and maintaining wind farms recognized in the first quarter (R$ 6.4 million). c) Other (O): R$ 53.1 million in 2Q26, a 29.7% increase compared to 2Q25 (R$ 40.9 million). The increase is primarily due to higher leasing expenses (R$ 6.2 million) and timing mismatches between quarters (R$ 10.2 million). Compared to 1Q26 (R$ 54.2 million), expenses remained in line. Other Operating Income The item Other Operating Results (Expens es) (ORO) amounted to revenue of R$ 47.9 million in 2Q26 compared with an expense of R$ 358.0 million in 2Q25. The variation is mainly explained by the mark -to-market effect of future energy contracts of R$ 96.7 million in 2Q26, due to the drop in the energy price curve, and -R$ 354.6 million in 2Q25. Additionally, in 2Q26, there was a provision of R$ 34.7 million related to litigations and judicial deposits. Adjusted EBITDA Auren reported an adjusted EBITDA of R$ 858.9 million in 2Q26, a decrease of 12.4% or -R$ 121.8 million compared to the same period the previous year. The decline is mainly explained by lower wind generation and EBITDA below the prior year in trading activities. Compared to 1Q26, there was a reduction of 7.2%, or R$ 67.0 million. These v ariations result from the effects detailed in the sections above on Net Margin and Costs and Expenses. The dividends declared on Auren's NCIs in 2Q26 totaled R$ 110.3 million vs. R$ 95.4 million in 2Q25, fully associated with NCIs in hydroelectric plants, in line with the strategy to distribute dividend payments more evenly throughout the year.
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22 Finance Income/Cost Consolidated Finance Income R$ million 2Q26 2Q25 Change 6M26 6M25 Change Finance Revenue 193.3 205.2 -5.8% 455.3 481.9 -5.5% Finance Costs1 (925.4) (849.7) 8.9% (1,777.2) (1,858.5) -4.4% Net Finance Income (Loss) (732.1) (644.5) 13.6% (1,322.0) (1,376.6) -4.0% The net finance result was an expense of R$ 732.1 million in 2Q26 compared with an expense of R$ 644.5 million in the same period of 2025. a) Finance Revenue: R$ 193.3 million in 2Q26 compared to revenue of R$ 205.2 million in 2Q25, due mainly to lower returns on financial investments as a result of the lower cash balance (R$ 4.7 billion in June 2026 vs. R$ 5.9 billion in June 2025). b) Finance Costs: R$ 925.4 million in 2Q26 vs. an expense of R$ 849.7 million in 2Q25. The increase of R$ 75.7 million is primarily due to the monetary restatement on debt due to the rise in the IPCA price index during the period (1.42% p.a. in 2Q26 vs. 0.93% p.a. in 2Q25) and costs associated with the corporate reorganization (R$ 16.9 million). Compared to 1Q26 (R$ 589.8 million), there was a 24.1% variation (R$ 142.3 million) in net finance income, mainly due to the arbitration process with a favorable ruling for Auren (R$ 25.9 million) recognized in the first quarter, in addition to the increase in interest and monetary restatement on debt (R$ 88.2 million) and litigation provisions (R$ 15.4 million) resulting from changes in restatement indices, as well as costs associated with the corporate reorganization. Net Profit Consolidated Net Income R$ million 2Q26 2Q25 Change 6M26 6M25 Change EBITDA 810.8 517.0 56.8% 1,110.9 1,894.5 -41.4% Depreciation and Amortization (465.4) (521.7) -10.8% (932.3) (979.9) -4.9% Share of profit (loss) of equity-accounted investees 39.6 14.8 168.3% 111.1 86.9 27.8% Net Finance Income (Loss) (732.1) (644.5) 13.6% (1,322.0) (1,376.6) -4.0% Taxes (IR/CSLL) (31.8) 71.7 n.a. 51.6 (133.7) n.a. Net Profit (379.1) (562.9) -32.7% (980.7) (508.9) 92.7% As a result of the aforesaid factors and changes in depreciation and amortization, equity income and taxes, the Company recorded a net loss of R$ 379.1 million in 2Q26 compared to a loss of R$ 562.9 million in 2Q25. The main changes were as follows. a) EBITDA: Consolidated EBITDA of R$ 810.8 million in 2Q26 versus R$ 517.0 million in 2Q25, an increase of R$ 293.8 million, primarily due to the mark-to-market of future energy contracts, as detailed previously. b) Depreciation/Amortization: an expense of R$ 465.4 million in 2Q26, lower than the amount observed in 2Q25 (R$ 521.7 million), in which the amortization of goodwill from AES Brasil and Esfera acquisitions occurred, and in line with the expense observed in 1Q26 (R$ 466.8 million). c) Income Tax and Social Contribution (IR/CS): expense of R$ 31.8 million in 2Q26, mainly driven by IR/CS paid on renewable assets under the Presumed Profit tax basis and tax losses arising from finance costs in certain entities where no deferred tax asset was recognized. d) Equity Income: revenue of R$ 39.6 million in 2Q26, R$ 24.8 million more than the amount recorded in 2Q25 (R$ 14.8 million). _________________________ 1 For comparability purposes, we highlight that the fair value effects of loans, financing, debentures and derivative financial instruments are presented net within finance costs, differing from the accounting treatment applied in the financial statements.
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23 Debt As of June 30, 2026, Auren's consolidated gross debt totaled R$ 23.5 billion, representing a reduction of R$ 1.0 billion (4.1%) compared to June 2025, reflecting the effects of liability management initiatives implemented over the last twelve months. Compared to March 31, 2026, gross debt decreased by R$ 199.5 million (0.8%), mainly due to the extraordinary amortization of R$ 187.0 million from the 1 st series of Auren Operações' 9 th Debenture Issuance (TIET19). In July, the Company made a new extraordinary amortization on TIET19, amounting to R$ 85 million. At the end of the quarter, leverage measured by the Net Debt/Adjusted EBITDA ratio reached 5.3x, compared to 5.2x on March 31, 2026, and 4.8x on June 30, 2025. The change in the indicator mainly reflects the reduction in the Adjusted EBITDA for the last twelve months, partially offset by the decrease in net debt. By the end of 2Q26, the Company's average debt term was 6.8 years, reflecting a balanced amortization profile without significant maturity concentrations. The average cost of gross debt was CDI -2.12% per year and the Company ended the period with a liquidity position of R$ 4.7 billion, strengthening its ability to manage financial obligations. Changes in Debt (R$ billion) and Proforma Gross Debt Profile Net Debt (R$ million), Leverage and Net Debt Profile1 Additionally, about 67% of net debt remains indexed to the IPCA, the same index that adjusts the Company's energy sale contracts, partially mitigating the Company's exposure to inflationary variations, while only 21% of net debt is tied to the CDI. As observed in the chart below, the liability management initiatives implemented throughout 2025 contributed to a more balanced maturity profile without significant concentrations of amortizations. _________________________ 1 Other includes incurred and paid interest, monetary restatement and the movement of deferred balances.
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24 Amortization Schedule of the Gross Debt Principal (R$ million) Debt R$ million Jun/26 Jun/25 Change Mar/26 Change Gross Debt 23,491.5 24,503.5 -4.1% 23,691.1 -0.8% Derivative Financial Instruments1 (6.9) (11.8) n.a. (35.6) n.a. Leases 162.7 167.3 -2.7% 165.2 -1.5% Adjusted Gross Debt2 23,647.3 24,659.0 -4.1% 23,820.7 -0.7% Liquidity3 4,739.9 5,910.8 -19.8% 4,719.0 0.4% Net Debt 18,907.5 18,748.2 0.8% 19,101.7 -1.0% Adjusted EBITDA 3,567.2 3,937.9 -9.4% 3,689.0 -3.3% Net Debt/Adjusted EBITDA 5.3x 4.8x 0.5x 5.2x 0.1x Financial Covenants – Auren Operações As disclosed to the market on June 1, 2026, Phase 1 of Auren Energia's corporate reorganization was completed on May 31, 2026, with the merger of Auren Participações into Auren Operações, which has universally succeeded it in all its rights and obligations. The operation represents an important step forward in streamlining the Company's corporate and financial structure, promoting greater efficiency in cash and debt management. Additionally, the reorganization temporarily eliminated Auren Operações' financial covenants for Net Debt/Adjusted EBITDA, previously applicable to the financing structure, providing the Company with greater financial flexibility. Following this development, the debts currently contracted at Auren Operações will come with corporate guarantee from Auren Energia. The definitive elimination of the covenants will occur upon the completion of Phase 2 of the corporate reorganization, when Auren Operações will be merged into CESP. Upon completion of the operation, the Company will no longer have corporate covenants, maintaining only project-level restrictive clauses. Ratings Throughout 2Q26, Auren maintained its corporate ratings at the highest level on the national scale (AAA) as per Fitch Ratings and Moody's. Moody's reaffirmed the stable outlook for the Company, while in July, Fitch revised its outlook from stable to negative. The maintenance of the ratings reinforces the solidity of the Company's financial fundamentals. _________________________ 1 Includes mark-to-market of financial derivatives, except for those related to energy trading operations. 2 Includes loans, financing and debentures, net of the related derivatives operations. 3 Cash, cash equivalents, short-term investments, liquidity fund (reserve account).
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25 Movement in Net Debt R$ million 2Q26 2Q25 Change Gross Debt - Opening Balance (1Q) 23,691.1 25,992.3 (2,301.2) Derivative Financial Instruments and Leases - Opening Balance (1Q) (129.7) (160.6) 31.0 Cash + Liquidity Fund + Short-term Investments - Opening Balance (1Q) 4,719.0 7,191.1 (2,472.1) Net Debt - Opening Balance (1Q) (A) 19,101.7 18,961.8 139.9 Adjusted EBITDA 858.9 980.6 (121.8) Provision for Reimbursement 103.1 75.1 28.1 Reimbursement Payment - (1.9) 1.9 Working Capital 135.2 49.0 86.2 Income Tax and Social Contribution Paid (93.8) (87.5) (6.3) Sustaining Capex (69.9) (81.0) 11.1 Return on Cash + Liquidity Fund + Financial Investments 148.5 219.3 (70.8) Interest Paid on Debt and Derivatives (566.7) (799.6) 232.9 Provision for Dividends on Equity Interests (110.3) (95.4) (14.8) Dividends Received from Equity Interests 64.6 45.3 19.3 Dividend Payment to Auren Energia Shareholders - (59.6) 59.6 Dividend Payment to Noncontrolling Shareholders1 - (1.8) 1.8 Other - 63.5 (63.5) Cash Movement (B) 469.6 306.0 163.6 Interest Capitalized on Debt and Derivatives 298.5 (99.2) 397.7 Amortization of Issuance Costs 12.8 40.6 (27.8) Adjustment to fair value (112.4) 37.7 (150.1) Provision for Leases 7.0 7.2 (0.2) Non-Cash Movement (C) 205.9 (13.7) 219.5 Net Debt Movement without Expansion (D) = (C) – (B) (263.8) (319.7) 55.9 Capex Growth (E) (69.5) (106.1) 36.5 Net Debt Movement with Expansion (F) = (D) – (E) (194.2) (213.6) 19.4 Net Debt - Closing Balance (2Q) (G) = (A) + (F) 18,907.5 18,748.2 159.3 Derivative Financial Instruments and Leases - Closing Balance (2Q) (155.8) (155.5) (0.3) Cash + Liquidity Fund + Short-term Investments - Closing Balance (2Q) 4,739.9 5,910.8 (1,170.9) Gross Debt - Closing Balance (2Q) 23,491.5 24,503.5 (1,012.0) Some of the main effects that influenced the variation in free cash flow between the periods are: a) Reimbursement: provision of R$ 103.1 million in 2Q26 vs. R$ 75.1 million in 2Q25, due to lower generation from wind assets. In the quarter, no reimbursement was made due to the suspension of returns amid regulatory discussions on curtailment. b) Sustaining Capex: capex expenditure of R$ 69.9 million in 2Q26 related to the mainte nance of the Company's hydroelectric, wind and solar assets. c) Return on Cash, Liquidity Fund and Short-term Investments: decrease of R$ 70.8 million in finance income due to the reduction in Liquidity (R$ 4.7 billion in March 2026 vs. R$ 7.2 billion in March 2025). d) Dividends: (i) provision for dividends declared on NCIs in HPPs during the quarter (R$ 110.3 million in 2Q26 vs. R$ 95.4 million in 2Q25) and an increase of R$ 19.3 million in the amount of dividends received from NCIs in HPPs compared to the sa me period of the previous year, due to changes in dividend recognition policies and terms _________________________ 1 Includes noncontrolling shareholders of Guaimbê Holding, Veleiros Holding, and Potengi Holding.
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26 implemented in 2025, and (ii) dividend payment to Auren Energia's shareholders in 2Q25 in the amount of R$ 59.6 million. e) Working Capital: working capital in 2Q26 (R$ 135.2 million) was mainly influenced by timing differences between the accounting recognition of revenues and expenses and their cash effects. The major variations are related to accounts receivable and payable for energy (+R$ 101.3 million). f) Interest paid: R$ 566.7 million in 2Q26, marking a reduction of R$ 232.9 million compared to 2Q25, mainly explained by the liability management strategy executed throughout 2025. g) Project Capex: expansion-related Capex in 2Q26 totaled R$ 69.5 million, primarily reflecting the implementation of the Cajuína 3 project. As of June 30, 2026, R$ 614.0 million was invested in Cajuína 3, around 83% of projected Capex, with physical progress reaching 88%. Statement of Profit or Loss by Segment The table below presents the State ment of Profit or Loss for each business segment —Generation, Trading and Holding— along with the necessary eliminations to arrive at the consolidated result for the period. Quarterly Statement of Profit or Loss by Segment and Consolidated – 2Q26 R$ million Generation Trading Holding Company Eliminations Consolidated Gross Revenue 1,957.8 2,257.2 - (733.8) 3,481.1 Deductions on Gross Revenue (192.1) (257.6) - 24.2 (425.6) Net Revenue 1,765.7 1,999.5 - (709.7) 3,055.5 Power Purchase Cost (518.8) (1,981.4) (0.0) 709.7 (1,790.5) Electricity grid usage charges (185.9) (0.2) 0.4 - (185.6) Net Margin 1,061.0 18.0 0.4 - 1,079.4 Net Margin 60.1% 0.9% - - 35.3% Costs and Expenses (PMSO) (258.3) (32.1) (26.1) - (316.5) Other Operating Income (OOI) (45.4) (216.2) (0.3) 309.8 47.9 EBITDA 757.3 (230.3) (26.0) 309.8 810.8 Mark-to-Market Adjustment of Energy Futures (ORO) - 213.1 - (309.8) (96.7) NCI Dividends 110.3 - - - 110.3 Accrual/(Reversal) of Provision for Litigation and Write-off of Judicial Deposits (ORO) 34.5 0.0 0.1 - 34.7 Adjusted EBITDA 902.1 (17.2) (25.8) - 858.9 Adjusted EBITDA Margin 51.1% -0.9% - - 28.1% Depreciation and Amortization (444.3) (4.6) (16.6) - (465.4) Share of profit (loss) of equity-accounted investees 41.0 (1.4) - - 39.6 Net Finance Income (Loss) (637.5) 15.1 (109.7) - (732.1) EBT (283.5) (221.3) (152.2) 309.8 (347.2) Taxes (IR/CSLL) (18.0) 71.5 20.0 (105.3) (31.8) Net Profit (301.5) (149.8) (132.2) 204.4 (379.1)
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27 Financial Performance – Generation Segment Note: Given the development of the Company's intersegment expenses sharing methodology, we began reporting the open generation EBITDA between hydropower sources in order to assist the market in analyzing the results and to facilitate the visualization and interpretation of the Company’s 2Q26 data, the figures related to the 2025 Financial Statements by segment are presented on an unaudited pro -forma basis, and include the apportionment methodology applied to the Company since 01/01/2025, solely to facilitate a comparative analysis. Results for the period R$ million 2Q26 2Q25 proforma Change 6M26 6M25 proforma Change Gross Revenue 1,957.8 1,822.8 7.4% 3,855.4 3,614.5 6.7% Deductions on Gross Revenue (192.1) (226.1) -15.0% (386.5) (396.7) -2.6% Net Revenue 1,765.7 1,596.8 10.6% 3,468.9 3,217.8 7.8% Power Purchase Cost (518.8) (334.9) 54.9% (931.8) (523.6) 77.9% Electricity grid usage charges (185.9) (176.6) 5.3% (364.4) (356.7) 2.1% Net Margin 1,061.0 1,085.3 -2.2% 2,172.7 2,337.4 -7.0% Net Margin 60.1% 68.0% -7.9 p.p. 62.6% 72.6% -10.0 p.p. PMSO (258.3) (238.0) 8.5% (509.3) (485.8) 4.8% Other Operating Income (OOI) (45.4) (1.2) n.a. (48.2) 4.5 n.a. EBITDA 757.3 846.1 -10.5% 1,615.2 1,856.1 -13.0% NCI Dividends 110.3 95.4 15.6% 199.6 153.7 29.8% Non-Recurring Items Related to Growth Initiatives - 7.0 n.a. - 8.4 n.a. Accrual/(Reversal) of Provision for Litigation and Judicial Deposits 34.5 (2.0) n.a. 64.7 (25.3) n.a. Write-off of PPE - - n.a. - 10.2 n.a. Adjusted EBITDA 902.1 946.4 -4.7% 1,879.5 2,003.1 -6.2% Hydro 452.1 461.7 -2.1% 1,067.7 1,038.6 2.8% Wind 387.4 432.9 -10.5% 694.9 827.3 -16.0% Solar 62.5 51.9 20.5% 116.9 137.2 -14.8% Adjusted EBITDA Margin 51.1% 59.3% -8.2 p.p. 54.2% 62.3% -8.1 p.p. The Adjusted EBITDA for the generation segment totaled R$ 902.1 million in 2Q26, R$ 44.4 million (4.7%) less than in 2Q25. The change in the period mainly reflects: a) Net Margin: R$ 1,061.0 million in 2Q26, a decrease of 2.2% compared to the same period of the previous year (R$ 1,085.3 million), equivalent to R$ 24.3 million, due mainly to the following impacts on hydro, wind and solar sources: - Hydroelectric Source: reduction in margin by R$ 28.6 million primarily due to lower prices in hydroelectric ACL contracts between periods (R$ 41.8 million), the transfer of the 150 MW contrac t to the Trader (R$ 15.9 million), and the increase in Sectoral Charges (R$ 8.2 million) due to monetary restatement, partially offset by higher modulation gains (R$ 32.7 million) and higher MRE income (R$ 7.5 million). The lower hydroelectric prices were already reflected in the quarterly published Energy Balance, noted in the variation of the average selling price in the ACL hydroelectric contracts between 2025 and 2026. - Wind Source: margin reduction of R$ 12.6 million due to a 9.9% decrease in wind generation, mainly driven by lower wind resources (R$ 44.3 million) and curtailment (R$ 21.1 million), partially offset by the monetary restatement of ACL and ACR contracts (R$ 35.7 million), the positive temporal effect of a realized provision (R$ 11.7 million), and gains from higher allocation in the ACR due to the price difference between regulated contracts and the PLD (R$ 4.5 million). - Solar Source: increase in net margin by R$ 16.9 million, mainly due to the positive impact of a temporary effect from a provision made (R$ 14.6 million) and a 7.2% increase in solar generation (R$ 3.3 million). Compared to the Net Margin from 1Q26 (R$ 1,111.8 million), there was a reduction of 4.6% (R$ 50.8 million) in 2Q26, mainly explained by the seasonality of generation sources, reduced modulation gains (R$ 26.7 million), and a greater gross impact from curtailment (R$ 11.6 million).
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28 b) PMSO: R$ 258.3 million in 2Q26, a nominal increase of 8.5% compared to 2Q25, mainly due to higher personnel expenses (R$ 7.0 million) driven by period inflation and other labor expenses, higher leasing costs (R$ 4.5 million), and timing mismatches between quarters (R$ 10.2 million). c) ORO: expense of R$ 45.4 million in 2Q26 compared to an expense of R$ 1.2 million in 2Q25, due to provisions made for lawsuits and judicial deposits (R$ 34.5 million). d) Dividends: dividends declared by hydropower assets in which the Company holds noncontrolling interests of R$ 110.3 million in 2Q26, R$ 14.9 million more than the same period last year. The incr ease is mainly due to changes in dividend recognition policies and bases for these assets carried out in 2025. Financial Performance of the Trading Segment Results for the period R$ million 2Q26 2Q25 proforma Change 6M26 6M25 proforma Change Gross Revenue 2,257.2 2,148.1 5.1% 4,536.4 4,218.9 7.5% Deductions on Gross Revenue 257.6 253.9 1.5% 511.9 536.9 -4.7% Net Revenue 1,999.5 1,894.2 5.6% 4,024.6 3,682.0 9.3% Power Purchase Cost (1,981.4) (1,812.8) 9.3% (3,998.6) (3,411.5) 17.2% Electricity grid usage charges (0.2) (0.1) 38.9% (0.2) (0.5) -49.5% Net Margin 18.0 81.3 -77.8% 25.7 270.0 -90.5% Net Margin 0.9% 4.3% -3.4 p.p. 0.6% 7.3% -6.7 p.p. PMSO (32.1) (31.5) 2.1% (66.5) (64.1) 3.7% Other Operating Income (OOI) (216.2) 77.3 n.a. 205.1 44.1 364.9% EBITDA (230.3) 127.1 n.a. 164.3 250.0 -34.3% Mark-to-Market Adjustment of Energy Futures 213.1 (77.1) n.a. (205.3) (38.4) n.a. Accrual/(Reversal) of Provision for Litigation and Write-off of Judicial Deposits 0.0 (0.0) n.a. 0.0 0.1 -98.0% Other Adjustments - 3.1 n.a. - 3.1 n.a. Adjusted EBITDA (17.2) 53.0 n.a. (41.0) 214.7 n.a. Adjusted EBITDA Margin -0.9% 2.8% -3.7 p.p. -1.0% 5.8% -6.8 p.p. Adjusted EBITDA reached -R$ 17.2 million in 2Q26 compared to R$ 53.0 million in 2Q25. Had the aforesaid contract transfer not occurred, the Adjusted EBITDA for 2Q26 would have been -R$ 1.3 million. The variation vs. 2Q25 is mainly explained by: a) Net Margin: excluding the negative impact of R$ 15.9 mi llion in the Trading segment in 2Q26, related to the assignment of the 150 MWavg contract mentioned in previous releases, we would have a negative variance of R$ 47.0 million between periods. This variation is mainly explained by the lower sales margin. There was an increase of about R$ 8.4 million compared to 1Q26 (R$ 9.6 million), mainly explained by lower energy purchase costs due to market price variations between periods. b) PMSO: operating costs and general and administrative expenses for the trading segment totaled R$ 32.1 million in 2Q26, compared to R$ 31.5 million in 2Q25. The variations primarily reflect the addition of Way2, with an impact of R$ 8.1 million, substantially offset by reduced outsourced service expenses. Compared to 1Q26 (R$ 34.3 million), these expenses decreased by 12.2% due to optimization of the aforesaid outsourced services item. c) ORO: revenue of R$ 216.2 million, mainly resulting from the mark -to-market of future energy sale contracts, totaling R$ 213.1 million in the quarter.
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29 Financial Performance of Noncontrolling Interests In this section, we present a Managerial Income Statement consolidating the financial performance of hydro assets in which Auren holds NCIs. This presentation is managerial, unaudited, and aims to help you understand the cash flow these assets generate, which ultimately results in dividend distribution to the Company. The table below highlights key items of these assets’ results, jointly weighted by Auren’s indirect equity interest, providing clearer insight into their operations. Note that none of the assets considered in this section carries debt on their individual balance sheets. Managerial P&L for Hydro Assets with NCIs Managerial P&L Interests (R$ million based on Auren’s equity interest) 2Q26 2Q25 proforma Change 6M26 6M25 proforma Change Volume of Energy Sold (MWavg) 257 247 4.0% 274 276 -0.7% Net Margin (R$/MWh) 232 202 14.7% 236 188 25.3% Net Margin 130.3 109.6 18.9% 281.0 228.7 22.9% PMSO (6.1) (5.9) 2.7% (11.4) (11.4) -0.2% Adjusted EBITDA1 124.3 103.6 19.9% 269.7 217.3 24.1% Depreciation & Amortization (10.4) (9.4) 11.1% (20.8) (18.8) 10.9% Other Results (Including MtM) (4.8) (28.1) -83.1% 1.1 4.2 -74.8% EBIT 109.1 66.1 64.9% 249.9 202.6 23.3% Finance Income/Cost (0.9) 6.4 n.a. 3.4 6.5 -47.4% EBT 108.2 72.5 -49.2% 253.3 209.1 21.1% Income Tax/Social Contribution (30.2) (24.8) 21.8% (65.0) (52.0) 25.0% Net Income2 78.0 47.8 63.3% 188.3 157.0 19.9% Dividends Announced 110.2 76.1 44.8% 199.5 134.4 48.4% 2Q26 at a glance: a) Net Margin: a positive variation in margin, of R$ 20.7 million, mainly explained by price adjustments and increases in Pollarix and CBA Energia's sales contracts between 2Q26 and 2Q25, as stipulated in the contracts. Additionally, the margin was boosted by cost reductions, contributing R$ 2.4 million, and a 4% increase in energy sales volume, enhancing the quarter's performance. b) PMSO: the PMSO remained consistent with the amount observed in the previous year (R$ 6.1 million in 1Q26 vs. R$ 5.9 million in 2Q26). c) Adjusted EBITDA: R$ 124.3 million in 2Q26, a 19.9% increase compared to the R$ 103.6 million recorded in 2Q25, mainly driven by the R$ net margin growth between the periods. d) Other Results: a positive variation of R$ 23.3 million between the compared quarters results from the mark-to- market effects of energy contracts, reflecting the decline in the future energy price curve. e) Financial Result: in 2Q26, the financial result was a loss of R$ 0.9 million, reversing the positive result of R$ 6.4 million observed in 2Q25. The variation between periods is mainly explained by the following effects: (i) monetary restatement of the UBP balance due to the increase in the index (IGP -M) applied to the UHEs Picada, Baesa, Enercan, Amador; and (ii) r eduction in finance income from investments in Pollarix Holding and Amador Aguiar. f) Announced Dividends: R$ 110.3 million in the second quarter of 2026, compared to R$ 76.1 million in 2Q25, due to better earnings for the year calculated in 2026 at Pollarix and CBA Energia. _________________________ 1 Adjusted EBITDA excludes mark‑to‑market effects. 2 Net Income reported can be found in Note 11 of Auren Energia’s Financial Statements, which is the sum of the share of profit (loss) of the equity-accounted investees Pollarix, CBA Energia Participações and Pinheiro Machado Participações.
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30 Other Material Information Ordinance No. 140/2026 on the Commitment Term for Curtailment On July 21, 2026, Ordinance No. 140/2026 (PRT 140) was published, establishing guidelines for the operationalization of cost compensation resulting from generation cuts in wind and solar photovoltaic plants as provided in Article 1º -B of Law No. 10.848, dated March 15, 2004. The cuts to be compensated include recognition for reliability and external unavailability compensation for wind and solar photovoltaic plants in the SIN for the period between September 2023 to November 2025. The Ordinance officially establishes the Commitment Term and guidelines for the operationalization of cost compensation resulting from these cuts. It should be noted that PRT 140 does not include recognition of curtailment for energy reasons, nor does it address reimbursement for curtailment occurring from November 2025 onwards, which remains to be regulated by ANEEL. For Auren, curtailment cuts classified as reliability or external unavailability (REL) below the threshold to 50% of the curtailment in the period covered by the Law, with an estimated impact of approximately R$ 300.0 million considering full compensation. The Company is currently analyzing the content of the Commitment Term from a legal perspective, as well as measuring the compensation under the new ordinance's guidelines, to assess the feasibility o f expressing prior interest to join by August 10, as established by the regulations. It should be noted that this expression of interest is not binding. Should there be an expression of interest, curtailment and reimbursement values will be reviewed by ONS and CCEE in light of what the Ordinance establishes. After this stage, the values will undergo a period of contestation by agents, and after this period, the amounts to be reimbursed will be established. Following the disclosure of the final values, agents may then opt for the definitive signing of the Commitment, on a date to be defined by the MME. According to the deadlines set by the publication, we estimate that document signatures will take place around the second quarter of 2027 and that payments related to reimbursements will effectively start in the second half of 2027. Access the full document published here (Portuguese only). Corporate Reorganization As announced in Material Facts disclosed on April 14, 2026 and June 24, 2026, and in the Announcement of June 1, 2026, the Company informed its shareholders and the general market about the progress of the corporate reorganization of Auren Energia's business group. The reorganizations primarily aims to: (a) concentrate hydroelectric assets in a single vehicle (CESP – Companhia Energética de São Paulo); (b) rationalize and streamline the corporate structure of the Auren Energia business group, reducing the number of publicly traded companies; and (c) increase cash and debt management efficiency. The Corporate Reorganization was structured in two sequential phases, subject to the fulfillment of the usual precedents for this type of operation, including regulatory approvals and third-party consents. On May 31, the Company completed Phase 1 of the corporate re organization, involving the conclusion of the downstream merger of Auren Participações into Auren Operações. Following the completion of this stage, Auren Participações was dissolved, and Auren Operações universally succeeded all its rights and obligations, becoming a wholly- owned subsidiary of Auren Energia. Consequently, the debentures previously issued by Auren Participações are now issued by Auren Operações, retaining their terms and respective trading codes. On June 24, the Boards of Directors of Auren Energia, CESP, and Auren Operações approved Phase 2 of the corporate reorganization, comprised of: (a) Phase 2 – Step 1: the transfer by Auren Energia of certain assets and liabilities to CESP through a capital contribution, including 1 00% of the common, registered, book -entry and no -par value shares issued by Auren Operações, and the drop-down of Auren Energia's 3rd Debenture Issuance (R$ 2.5 billion), aligning debt allocation with the assets’ operational cash generation. As a result, CESP will become the direct shareholder corresponding to 100% of Auren Operações' share capital. (b) Phase 2 - Step 2: the merger of Auren Operações by CESP, resulting in its dissolution and consolidating the hydroelectric assets and corresponding operational structure in CESP. The implementation of Phase 2 remains conditional upon the fulfillment of the precedents outlined for the operation, including, among other things, obtaining applicable regulatory authorizations, especially from ANEEL, consents from the debenture holders, and other involved third parties, and meeting other conditions stipulated in the operation documents. The Company will keep its shareholders and the market duly informed about any material developments.
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31 Corporate Reorganization Steps Contingent Liabilities In line with market best practices, Auren discloses its contingent liabilities covering both probable and possible loss estimates. The Company is currently party to lawsuits totaling R$ 899 million in provisions (probable losses) and R$ 2,986 million in contingencies classified as possible losses. The consolidated amount of R$ 3,885 million represents a R$ 201 million decrease compared to the 4th quarter of 2025, mainly reflecting procedural developments and monetary restatement. The most significant development concerns the Company's resounding victory in a tax proceeding. Contingent Liabilities – Probable and Possible As shown in the graph below, under the designation "Contingent Liability Profile," the distribution of risk provisioned by legal nature reveals a predominance of the civil portfolio, which accounts for 59% of the likely risk. These mostly include indemnification claims as well as regulatory and real estate disputes (excluding expropriation cases), with a total of 1,183 ongoing lawsuits.
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32 Probable Contingent Liabilities (% of Total) Auren emphasizes that the value of contingent liabilities is regularly reviewed, as its measurement is indexed to the Company’s best risk prognosis, including the progression of court cases.
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33 Quarterly Overview SIN Reservoir Levels (% Maximum Energy Stored) Energy Allocated in MRE (GWavg) The improvement in hydrological conditions during the second quarter and lower -than-expected demand supported the recovery of SIN reservoirs, helping drive down energy prices during the period. The GSF reached 99% in 2Q26 (+3 p.p. vs. 2Q25), reflecting a combination of higher hydroelectric generation and lower allocation of firm power by MRE participants. Wind and Solar Curtailment and Modulation Summary Financials 2Q26 Wind Solar SIN Curtailment C (%) 15.7% 25.8% Auren Curtailment (%) 12.9% 26.0% Effective Auren Generation (% of P50) 84.3% 67,8% Auren Curtailment by Source (R$ million) 77.8 20.1 Auren Consolidated Curtailment (R$ million) 97.8 (-) Modulation gains (R$ million) 70.5 (=) Curtailment Net of Modulation (R$ million) 27.3 Adjusted EBITDA of R$ 858.9 million (-12.4% vs. 2Q25), influenced by: o Lower wind resources , with a negative deviation of 4.4 p.p. compared to asset certification in 2Q26 and increased curtailment. o Curtailment of R$ 97.8 million in the quarter, largely offset by R$ 70.5 million in modulation gains during the period. o Lower results from the Trading in 2026, due to lower trading margins. Reduction in net debt, with a slight increase in leverage (5.3x Net Debt/Adjusted EBITDA) due to a decrease in the EBITDA of the past 12 months. Consolidated Power Balance Auren reports Adjusted EBITDA of R$ 859 million in 2Q26, highlighted by the start of the run-test activities at the Cajuína 3 Complex