Earnings release
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Pampa Energía, an independent company with active participation in the Argentine oil, gas and electricity, announces the results for the nine-monthperiod and quarter ended on September 30, 2025. Stock information Buenos Aires, November 4, 2025Basis of presentation Pampa reports its financial information in US$, its functional currency. For local currency equivalents, transactionalFX is applied. However, Transener and TGS’s figures are adjusted for inflation as of September 30, 2025, andconverted into US$ using the period-end FX. Previously reported figures remained unchanged. Q3 25 main results1 Sales recorded US$591 million in Q3 252, a 9% year-on-year increase driven by higher crude oil productionin Rincón de Aranda, increased gas exports to Chile, and fuel self-procurement at CTLL, partially offset by lower gassales to retailers, a decline in crude oil prices and weaker petrochemical sales. During Q3 25, shale oil production at Rincón de Aranda continued to grow steadily, consolidating the block’sexpansion. Note: * Price net of export duty and quality/logistic discounts. Adjusted EBITDA3 reached US$322 million in Q3 25, a 16% year-on-year increase, mainly reflecting thestrong contribution from Rincón de Aranda and, to a lesser extent, from gas exports, higher margins on self-procured gas and PEPE 6. These effects were partially offset by lower styrene margins and reduced residential gasdemand. Net income attributable to shareholders was US$23 million, 84% below Q3 24, mainly explained by highernon-cash deferred tax charges, which also impacted results on our affiliates’ equity income, partially offset byimproved operating margins. Net debt totaled US$874 million as of September 2025 vs. US$712 million as of June 2025, resulting in a net-debt to EBITDA ratio of 1.3x, mainly due to higher investments in the development of Rincón de Aranda and sharebuybacks. After the quarter’s closing, net debt decreased to US$790 million, resulting in a 1.1x ratio. Buenos Aires StockExchangeTicker: PAMP New York StockExchangeTicker: PAM1 ADS = 25 commonshares Share capital net ofrepurchases as of November 3,2025:1,343.6 million common shares/53.7 million ADS Market capitalization:AR$7,269 billion/US$4,761 million Information about thevideoconference Date and time:Wednesday, November 510 AM Eastern Standard Time12 PM Buenos Aires Time Access link:bit.ly/Pampa3Q2025VC For further informationabout Pampa Emailinvestor@pampa.com Website for investors ri.pampa.com/en Argentina’s Securities andExchange Commissionwww.argentina.gob.ar/cnv US Securities andExchange Commissionsec.gov Pampa's main operational KPIs Q3 25 Q3 24 VariationOil and gas Production (kboe/day) 99.5 87.5 +14% Gas production (kboepd)82.2 82.1 +0% Crude oil production (kbpd)17.3 5.4 +220% Average gas price (US$/MBTU) 4.4 4.4 +0% Average oil price (US$/bbl)*61.1 71.9 -15% Power Generation (GWh) 5,421 5,951 -9% Gross margin (US$/MWh)26.5 22.6 +17% Petrochemicals Volume sold (k ton) 122 128 -4% Average price (US$/ton)937 1,092 -14% 1 The information is based on FS prepared according to IFRS in force in Argentina. 2 Sales from the affiliates CTBSA, Transener and TGS are excluded, shown as ‘Results for participation in joint businesses and associates.’ 3 Consolidated adjusted EBITDA represents the flows before financial items, income tax, depreciations and amortizations, extraordinary and non-cash income and expense, equity income, andincludes affiliates’ EBITDA at our ownership. Further information on section 3.1. Earnings release Q3 25 ● 1
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1. Relevant events 1.1 Power generation New rules for the WEM normalization On October 21, 2025, the SE introduced, a new framework for the WEM’s progressive normalization, aimed at fostering greater competitionamong generators, encouraging direct contracting between demand and generators, and promoting a more decentralized fuel-supply scheme. EffectiveNovember 1, 2025, the new framework introduces changes to the spot market and splits the forward market into two segments: energy and capacity. Italso allocates part of the supply to seasonal procurement for distribution companies (Resolution No. 400/25). Under the new forward market rules, thermal and hydro power plants commissioned before January 1, 2025, may sell PPAs i) up to 100% oftheir energy to distribution companies, or ii) up to 20% to large users. Regarding capacity, they may contract 100% of their availability with any demand. Starting in 2030, generators will be free to contract PPAs for any demand segment4. In the spot market, energy remuneration —known as Adjusted Marginal Rent (RMA)— will follow a marginal pricing system, defined as RMA =(CMgh × FP – CVP) × FRA, where CMgh is the system’s hourly marginal cost, FP the loss factor of the corresponding node, and CVP the declared variable production cost of each unit. For thermal generation, the RMA is capped by the Adjusted Rent Factor (FRA), which determines the share of margin retained by eachgenerator: i) new generation FRA = 1, retaining the full margin; ii) legacy generation with own fuel procurement 15% from 2025, 25% from 2027, and35% from 2028; iii) legacy generation with gas supplied by CAMMESA 12% from 2025, 15% from 2027, and 17.5% from 2028; and iv) legacygeneration without fuel management FRA = 0, with CVP based on regulated values. For hydroelectric, renewable or self-generated power, the same marginal pricing scheme applies, although it assumes CVP = 0. Unitscommissioned before January 1, 2025, maintain a FRA equivalent to thermal generation, with minimum RMA floors of i) US$22/MWh for hydroelectricplants; and ii) US$32/MWh for renewable or self-generating units. Plants commissioned from 2025 onward apply FRA = 1, with no floor or ceiling. In terms of capacity payments in the spot market, the Available Capacity (PPAD) is set at US$12/MWh, remunerating 90 hours per week andapplying a weighting factor: i) for plants using natural gas only, 1.1 in summer/winter and 0.9 during the rest of the year; and ii) for plants usingalternative fuels, 1.5 in summer/winter and 1.0 during the rest of the year. Plants without fuel or supplied by CAMMESA will receive capacity paymentsat 100% when dispatched, and at decreasing percentages when idle: 80% until December 2026, 40% during 2027, and 0% from 2028 onward.Additionally, a base reliability reserve payment of US$1,000/MW-month is recognized, regardless of technology or fuel management. Regarding fuel management, CAMMESA will remain the supplier of last resort until 2029, after which power generators will assume fullresponsibility for fuel sourcing. Generators must provide their own alternative fuels (fuel oil or diesel). For natural gas, generators may choose between:i) self-procurement, or ii) contracting through CAMMESA while the Gas Plan remains in force, with costs reflecting the weighted average of all Gas Planand/or LNG imports, updated biweekly. This new framework upholds existing PPAs, whose energy output remains allocated to meet distribution companies’ seasonal demand until theirexpiration. Once PPAs expire, generators may either operate in the spot market or sell PPAs to distributors or large users. Under this new regime, efficient, well-located units with fuel self-procurement could achieve higher profit margins, entirely in US$. Among thoseunits, Pampa operates three strategically located CCGTs: CTLL in Vaca Muerta; CTGEBA at the central system node; and CTEB, which uses natural gasand diesel, with a 50% equity stake. Pampa also operates open-cycle CPB (which fires fuel oil), CTG, and CTP. 4 In the case of hydroelectric generation, it may only provide backup for up to 70% of the contracted demand. Earnings release Q3 25 ● 2
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Last price updates for the legacy or spot scheme Effective as of: Legacy energy/spotIncrease ResolutionJuly 2025 1% SE No. 280/25August 2025 0.4% SE No. 331/25 September 2025* 0.5% SE No. 356/25 October 2025* 0.5% SE No. 381/25 Note: *These updates exclude hydro power plants undergoing a tender process (Alicurá, El Chocón-Arroyito, Cerros Colorados, and Piedra del Águila). Extension of HIDISA’s hydroelectric concession On October 20, 2025, the SE proposed extending HIDISA’s concession until June 2026, subject to Pampa’s acceptance of the original contractand additional conditions, including updating guarantees, waiving any claims against the State related to changes in the remuneration scheme, andpaying royalties to the Province of Mendoza (Res. SE No. 398/25). HIDISA requested a 15-business-day extension to submit its decision, which, as of today, has not been addressed by the SE. If Pampa does notaccept the proposed terms, it will be required to continue operating the asset for 90 calendar days, allowing the National Government to implement thenecessary measures to ensure continued operation. Tender for Comahue hydroelectric power plants On August 19, 2025, the MECON launched a national and international tender for the transfer of share capital of the Alicurá, El Chocón–Arroyito,Cerros Colorados, and Piedra del Águila hydroelectric plants (Res. No. 1200/25). Bids are due on November 7, 2025. Pampa is currently assessing itsparticipation in the process. 1.2 Transener and TGS Award to TGS in the GPM expansion tender On October 17, 2025, the SE awarded TGS the GPM expansion project (Res. No. 397/25), consistent with the private initiative submitted by TGSin June 2024. The project involves installing three new compressor plants and adding 90,000 HP of capacity, increasing GPM’s transportation capacityfrom 21 mcmpd to 35 mcmpd. The expansion is expected to require an estimated investment of US$560 million, with works scheduled for completionbefore April 30, 2027. In addition, TGS will invest approximately US$220 million to expand transportation capacity by 12 mcmpd in the final sections of the trunkpipeline system, with repayment through TGS’s regulated tariff. Transener and Transba dividend distribution On September 1, 2025, Transener and Transba Shareholders’ Meetings approved a cash dividend of AR$134 billion and AR$44 billion,respectively. Pampa collected a total of US$25 million for its 26.3% participation in Transener. Last tariff updates Effective as of: Transener/Transba TGSIncrease Resolution Increase ResolutionJuly 2025 4.6%/1.5% ENRE No. 451 y 454/25 0.8% ENARGAS No. 421/25August 2025 6.0%/2.9% ENRE No. 549 and 555/25 1.8% ENARGAS No. 539/25September 2025 7.0%/3.8% ENRE No. 616 and 617/25 2.6% ENARGAS No. 622/25October 2025 7.1%/3.9% ENRE No. 675 and 676/25 2.7% ENARGAS No. 732/25November 2025 7.6%/4.4% ENRE No. 724 and 731/25 3.2% ENARGAS No. 812/25 Earnings release Q3 25 ● 3
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1.3 Sale of El Tordillo, La Tapera and Puesto Quiroga On October 1, 2025, Pampa transferred its 35.67% stake in the El Tordillo, La Tapera and Puesto Quiroga concessions for US$2 million, subjectto a clean exit condition. With this transaction, Pampa no longer holds assets in the San Jorge Gulf basin. 1.4 New share repurchase program On September 8, 2025, Pampa’s Board of Directors approved the 14th share repurchase program, for up to US$100 million or 10% of sharecapital, with a maximum price of US$60 per ADR or AR$3,480 per common share, effective for 120 days. To date, 0.8 million ADRs equivalent havebeen repurchased at an average of US$58.8/ADR, representing 1.5% of Pampa’s issued share capital. 1.5 Release of Guarantees in OCP Ecuador On November 30, 2024, OCP Ecuador transferred its ownership in the pipeline to the Ecuadorian State. As part of the transaction, OCP Ecuadorhad two outstanding guarantees —one operational and one environmental— totaling US$84 million. Under the terms of the concession agreement, the expiration of the license triggered the release of these guarantees on March 1, 2025, alongwith the corresponding monetary reimbursement to OCP Ecuador. However, Citibank Ecuador, the issuing bank, declined to release the guarantees onthat date, citing non-compliance with certain formal requirements. This led to the initiation of arbitration proceedings seeking the release of theguarantees and compensation for damages. Subsequently, on October 28, 2025, the Ecuadorian State formally notified Citibank Ecuador of the expiration of the guarantees and instructedtheir release, which was executed on November 3, 2025. As a result, Pampa added US$84 million to its cash position and reduced its net debt-to-EBITDA ratio to 1.1x. Earnings release Q3 25 ● 4
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2. Analysis of Q3 25 results Breakdown by segmentIn US$ million Q3 25 Q3 24 Variation SalesAdjustedEBITDANet IncomeSalesAdjustedEBITDANet IncomeSalesAdjustedEBITDANet Income Oil and Gas 308 171 (9) 228 122 (4) +35% +40%+125%Power generation 205 120 6 183 112 95 +12% +8% -94%Petrochemicals 115 (5) (2) 140 2 7 -18% NA NAHolding and Others 6 36 28 19 43 48 -68% -16% -42%Eliminations (43) - - (30) - - +44% NA NA Total 591 322 23 540 279 146 +9% +16% -84% Note: Net income is attributable to the Company’s shareholders. Reconciliation of adjusted EBITDA,in US$ million Nine-month period Third quarter 2025 2024 2025 2024 Consolidated operating income 402 392 168 154Consolidated depreciations and amortizations 305 257 124 105 Reporting EBITDA 707 649 292 259 Adjustments from oil and gas segment (11) 5 (7) 14Adjustments from generation segment 30 80 15 7Adjustments from petrochemicals segment (17) (0) (0) (0)Adjustments from holding & others segment 70 20 22 (1) Consolidated adjusted EBITDA 779 754 322 279At our ownership 777 754 322 279 Earnings release Q3 25 ● 5
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2.1 Analysis of the oil and gas segment Oil & gas segment, consolidatedFigures in US$ million Nine-month period Third quarter 2025 2024 ∆% 2025 2024 ∆% Sales revenue 658 596 +10% 308 228 +35%Domestic sales 515 512 +1% 231 201 +15%Foreign market sales 143 84 +70% 77 27 +185%Cost of sales (461) (387) +19% (191) (153) +25% Gross profit 197 209 -6% 117 75 +56% Selling expenses (56) (46) +22% (22) (17) +29%Administrative expenses (60) (57) +5% (20) (21) -5%Other operating income 41 67 -39% 25 25 -Other operating expenses (16) (22) -27% (8) (8) -Impairment of financial assets (5) (10) -50% (3) - NAImpairment on int. assets & inventories (8) (19) -58% (7) (19) -63%Results for participation in joint businesses 2 - NA - - NA Operating income 95 122 -22% 82 35 +134% Finance income - 1 -100% - 1 -100%Finance costs (77) (71) +8% (22) (22) -Other financial results (25) (17) +47% (25) (3) NAFinancial results, net (102) (87) +17% (47) (24) +96% Loss before tax (7) 35 NA 35 11 +218% Income tax (31) 36 NA (44) (15) +193% Net (loss)/income for the period (38) 71 NA (9) (4) +125% Adjusted EBITDA 298 310 -4% 171 122 +40% Increases in PPE and right-of-use assets 720 243 +196% 267 46 NADepreciation and amortization 214 183 +17% 96 73 +32%Lifting cost 162 131 +24% 59 48 +22%Lifting cost per boe 6.9 5.7 +22% 6.4 6.0 +7% Sales in the oil and gas segment rose 35% year-on-year and 51% quarter-on-quarter, mainly driven by strong crude oil production growth atRincón de Aranda, increased gas to Chile, fuel self-procurement at CTLL, and the industrial segment. These effects were partially offset by lower sales inSeptember, explained by weaker retail demand due to milder weather and the expiration of Plan Gas winter peak commitments, as well as lower crudeoil and gas export prices. Regarding the operational performance, total production averaged 99.5 kboepd in Q3 25 (+14% vs. Q3 24, +18% vs. Q2 25), mainlyexplained by sustained oil output growth at Rincón de Aranda following the completion of three new pads, and by higher gas production at Sierra Chata,which reached a new all-time high of 6.3 mcmpd in July. The increase vs. Q2 25 was driven by higher contributions from Rincón de Aranda and seasonalgas demand. Gas production averaged 14.0 mcmpd in Q3 25 (flat vs. Q3 24, +8% vs. Q2 25). Analyzing the gas output by block, El Mangrulloaccounted for 50% of the total gas output, averaging 7.0 mcmpd (-12% vs. Q3 24, -7% vs. Q2 25), followed by Sierra Chata with 5.3 mcmpd,contributing 38% of the production (+33% vs. Q3 24, +40% vs. Q2 25). At non-operated blocks, Río Neuquén produced 1.3 mcmpd(-20% vs. Q3 24, flat vs. Q2 25), while Rincón del Mangrullo and Aguaragüe continued their natural depletion, each producing 0.1 mcmpd. Earnings release Q3 25 ● 6
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Oil and gas'key performance indicators 2025 2024 Variation Oil Gas Total Oil Gas Total Oil Gas Total Nine-month period Volume Production In thousand m3/day 1.5 12,911 0.8 13,382 +89% -4% +2%In million cubic feet/day 456 473 In thousand boe/day 9.6 76.0 85.5 5.0 78.8 83.8 Sales In thousand m3/day 1.6 12,932 0.8 13,331 +111%-3% +4%In million cubic feet/day 457 471 In thousand boe/day 10.1 76.1 86.3 4.8 78.5 83.3 Average Price In US$/bbl 61.9 71.0 -13% -2% In US$/MBTU 3.9 3.9 Third quarter Volume Production In thousand m3/day 2.7 13,967 0.9 13,944 +220%+0% +14%In million cubic feet/day 493 492 In thousand boe/day 17.3 82.2 99.5 5.4 82.1 87.5 Sales In thousand m3/day 3.2 13,913 0.9 13,632 +267%+2% +19%In million cubic feet/day 491 481 In thousand boe/day 20.1 81.9 102.0 5.5 80.2 85.7 Average Price In US$/bbl 61.1 71.9 -15% +0% In US$/MBTU 4.4 4.4 Note: Net production in Argentina. Gas volume standardized at 9,300 kilocalories (kCal). Oil price is net of export duty and quality/logistic discounts. Our gas price averaged US$4.4 per MBTU in Q3 25 (flat vs. Q3 24, +11% vs. Q2 25 due to seasonality), supported by fuel self-procurement forCTLL during the winter peak and improved industry prices, partially offset by lower export prices. Regarding our gas deliveries by customer, during Q3 25, 39% was destined for thermal power generation (vs. 50% in Q3 24) and 33% todistribution companies (vs. 36% in Q3 24), both under Plan Gas GSA. The year-on-year decrease reflects the end of Plan Gas winter commitments inSeptember 2024, lower retail demand due to milder September weather, and fuel self-procurement in CTLL, which itself accounted for 6% of Q3 25deliveries. The industrial/spot market absorbed 12% (vs. 7% in Q3 24 due to increased transport capacity), 8% was exported (vs. 3% in Q3 24 due toincreased foreign demand), and the remaining 2% was sold to our petrochemical plants (vs. 3% in Q3 24). Oil production reached 17.3 kbpd in Q3 25 (+3.2x vs. Q3 24, 2.2x vs. Q2 25), driven by the ramp-up of shale oil output at Rincón de Aranda,which averaged 14.4 kbpd in Q3 25 (+13.2 kbpd vs. Q3 24,+6.9 kbpd vs. Q2 25) with 20 wells in production (vs. 2 in Q3 24, 10 in Q2 25). This growth was partially offset by the sale of Gobernador Ayala inOctober 2024 (-1.0 kbpd vs. Q3 24) and lower volumes from non-operated conventional crude oil blocks El Tordillo and Los Blancos (-0.2 kbpd vs. Q324). The average oil price, net of export duty and quality/logistic discounts, was US$61.1 per barrel (-15% vs. Q3 24, -1% vs. Q2 25), mainlyreflecting lower Brent prices. Without Rincón de Aranda’s partial price hedge, in place since April 2025, the average oil price would have been US$60.3per barrel. Exports accounted for 47% of total sales in Q3 25, similar to Q3 24, although export volumes quadrupled year-on-year. Earnings release Q3 25 ● 7
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The lifting cost4 totaled US$59 million in Q3 25 (+22% vs. Q3 24, flat vs. Q2 25), explained by higher gas treatment expenses and TPFleasing at Rincón de Aranda. Lower maintenance and labor costs offset those effects. The lifting cost per boe rose 7% to US$6.4 per boe produced inQ3 25 vs. US$6.0 per boe in Q3 24, mainly explained by higher operating expenses mentioned before, though partially offset by increased production atRincón de Aranda. Compared to Q2 25, the 15% decrease in lifting cost per boe reflects the growth in crude oil production and cost stabilization. Excluding depreciation and amortization and lifting costs, other operating costs increased 24% vs. Q3 24 and 33% vs. Q2 25, mainly due tohigher crude oil purchases for trading, royalties and levies in line with increased production, and higher export transportation costs. Other operating income and expenses remained flat vs. Q3 24. Higher environmental remediation and bad debts provisions were partiallyoffset by lower financial transaction taxes and a slight increase in Plan Gas compensation, driven by the devaluation impact on retail tariffs. In addition,improved collections from CAMMESA and ENARSA led to a decline in commercial interest income (-11% vs. Q3 24). Compared to Q2 25, other operatingnet income rose significantly, explained by higher Plan Gas compensation from seasonality and slightly higher days sales outstanding, partially offset byhigher environmental provisions. Financial results in Q3 25 posted net losses of US$47 million (+96% vs. Q3 24, +81% vs. Q2 25), mainly explained by higher FX losses froma steeper AR$ devaluation impacting the segment’s net monetary asset position in AR$, as well as lesser gains from holding financial securities, partiallyoffset by gains from the crude oil price hedge. Reconciliation of adjusted EBITDA from oil & gas,in US$ million Nine-month period Third quarter 2025 2024 2025 2024 Consolidated operating income 95 122 82 35Consolidated depreciations and amortizations 214 183 96 73 Reporting EBITDA 309 305 178 108 Deletion of int. assets & inventories' impairment 8 19 7 19Deletion of gain from commercial interests (7) (18) (5) (5)Deletion of CAMMESA's receivable impairment - 4 - -Deletion of SESA's equity income (2) - - -Deletion of TPF lease amortization (10) - (10) - Adjusted EBITDA from oil & gas 308 310 171 122 Our oil and gas adjusted EBITDA amounted to US$171 million in Q3 25 (+41% vs. Q3 24, +98% vs. Q2 25), mainly driven by acceleratedshale oil production at Rincón de Aranda and higher profit margins from fuel self-procurement for power generation, exports, and industrial demand.These effects were partially offset by lower retail gas sales. Growth of crude oil sales and seasonal gas deliveries explains the quarter-on-quarterimprovement in EBITDA. The adjusted EBITDA excludes non-recurring and non-cash income and expenses, as well as overdue commercial interests andequity income from affiliates, and includes a US$10 million adjustment to the rights-of-use amortization, reflecting the reclassification of the TPF rentalat Rincón de Aranda as lifting cost. Finally, capital expenditures amounted to US$267 million (5.8x vs. Q3 24, but -13% vs. Q2 25), with 65% allocated to the development ofRincón de Aranda. 4 It only considers maintenance, treatment, internal transportation, wellhead staff and the TPF costs at Rincón de Aranda, which under IFRS it is recorded as Leases, recording rights-of-useamortization in the cost of sales. Lifting cost does not include amortizations and depreciations. Earnings release Q3 25 ● 8
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2.2 Analysis of the power generation segment Power generation segment, consolidatedFigures in US$ million Nine-month period Third quarter 2025 2024 ∆% 2025 2024 ∆% Sales revenue 585 505 +16% 205 183 +12%Cost of sales (319) (260) +23% (114) (102) +12% Gross profit 266 245 +9% 91 81 +12% Selling expenses (3) (2) +50% (1) (1) -Administrative expenses (31) (39) -21% (10) (14) -29%Other operating income 17 34 -50% 4 2 +100%Other operating expenses (9) (11) -18% (4) (4) -Impairment of financial assets - (46) -100% - - NAResults for participation in joint businesses 5 (28) NA (2) 10 NA Operating income 245 153 +60% 78 74 +5% Finance income 15 3 NA 7 1 NAFinance costs (36) (39) -8% (11) (11) -Other financial results 81 102 -21% 1 22 -95%Financial results, net 60 66 -9% (3) 12 NA Profit before tax 305 219 +39% 75 86 -13% Income tax (180) 109 NA (69) 9 NA Net income for the period 125 328 -62% 6 95 -94%Attributable to owners of the Company 125 328 -62% 6 95 -94%Attributable to non-controlling interests - - NA - - NA Adjusted EBITDA 362 304 +19% 120 112 +8%Adjusted EBITDA at our share ownership 360 304 +18% 120 112 +7% Increases in PPE and right-of-use assets 46 67 -31% 18 24 -27%Depreciation and amortization 87 71 +23% 27 31 -13% In Q3 25, power generation sales increased 12% year-on-year, mainly driven by higher revenue from CTLL’s fuel self-procurement during thewinter peak and, to a lesser extent, by PEPE 6’s contribution, higher spot capacity prices and greater PPA sales to industrial clients. These effects werepartially offset by lower thermal dispatch. Compared to Q2 25, the sales growth reflects seasonal increases in generation and the completion ofscheduled maintenance at CTLL and CTEB. Increase in spot capacity payments was led by open cycles (GT and ST), which averaged US$5.9 thousand per MW-month (+22% vs. Q3 24 and+12% vs. Q2 25), due to the additional US$ remuneration in July and August under the 2024-2026 Contingency Plan (Res. SE No. 294/24). In contrast,CCGTs remained at US$5.3 thousand per MW-month (flat vs. Q3 24 and Q2 25), while hydros averaged US$2.1 thousand per MW-month (-8% vs. Q324, -8% vs. Q2 25). Compared to Q2 25, capacity improved, again driven by open cycles benefiting from this additional remuneration. The operational performance of Pampa’s operated power generation dropped 9% year-on-year, mainly due to lower thermal demand fromCAMMESA amid weak electricity consumption and higher penetration of renewable and nuclear power generation, as well as scheduled maintenanceoutages. This follows a 2% contraction in national power demand, linked to softer economic activity and milder weather. Analyzing by plant, lowergeneration stemmed from CTGEBA’s old CCGT (-131 GWh), open cycles (-166 GWh), reduced water input at HPPL (-166 GWh) and HINISA’s outage(-121 GWh). These declines were partially offset by PEPE 6’s contribution (+75 GWh) and higher CCGT output at new CTGEBA and CTLL (+44 GWh).Quarter-on-quarter, generation increased 15% following CTLL and CTEB’s planned overhauls inQ2 25. The total availability of Pampa’s operated units reached 94.0% in Q3 25, down from 96.7% in Q3 24 (-275 basis points), mainly impacted byprogrammed maintenance at CTGEBA’s GT04 and CTLL’s GT05, and forced outages at CTLL’s GT04 and HINISA, the latter ongoing since January. Thesevariations were partially offset by PEPE 6 and the recovery of CTLL’s GT05, which had been out of service in August 2024. Thermal availability, however,increased 40 basis points, reaching 97.1% in Q3 25. Earnings release Q3 25 ● 9
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Power generation'skey performance indicators 2025 2024 Variation WindHydroThermalTotal WindHydroThermalTotal WindHydroThermalTotal Installed capacity (MW) 427 938 4,1075,472 382 938 4,1075,426 +12% - +0% +1%New capacity (%) 100% - 33% 32% 100% - 33% 32% - - +0% +1%Market share (%) 1.0%2.1%9.4%12.5% 0.9%2.2%9.6%12.6% +0% -0% -0% -0% Nine-month period Net generation (GWh) 1,2441,02713,80616,077 839 1,64114,46716,947 +48%-37% -5% -5%Volume sold (GWh) 1,2541,02714,37616,657 844 1,64115,05417,539 +49%-37% -5% -5% Average price (US$/MWh) 70 22 40 41 72 15 35 35 -3% +48%+15%+18%Average gross margin (US$/MWh) 54 10 24 26 62 6 22 22 -13%+75%+10%+14% Third quarter Net generation (GWh) 420 249 4,7525,421 337 540 5,0745,951 +25%-54% -6% -9%Volume sold (GWh) 428 249 4,9085,585 340 540 5,2806,161 +26%-54% -7% -9% Average price (US$/MWh) 70 27 42 43 72 17 35 36 -3% +56%+18%+21%Average gross margin (US$/MWh) 54 9 25 27 54 6 22 23 -0% +50%+12%+17% Note: Gross margin before amortization and depreciation. Includes CTEB (co-operated by Pampa, 50% equity stake). Excluding depreciation and amortizations, net operating costs increased 14% to US$98 million in Q3 25, mainly explained by higher gaspurchases for CTLL’s self-procurement and greater maintenance expenses, partially offset by lower labor and insurance costs. Compared to Q2 25,operating expenses increased 17%, due to increased gas purchases, partially offset by reduced maintenance costs. Other operating income and expenses reached breakeven, improving from a US$2 million loss in Q3 24, mainly due to lower financialtransaction taxes, offset by higher repairments, net of insurance recoveries. Financial results in Q3 25 recorded a US$3 million net loss, compared to a US$12 million profit in Q3 24, reflecting lower gains on financialsecurities, partially offset by higher interest income. Reconciliation of adjusted EBITDA from power generation,in US$ million Nine-month period Third quarter 2025 2024 2025 2024 Consolidated operating income 245 153 78 74Consolidated depreciations and amortizations 87 71 27 31 Reporting EBITDA 332 224 105 105 Deletion of CTEB's equity income (5) 28 2 (10)Deletion of commercial interests to CAMMESA (4) (28) (2) (2)Deletion of CAMMESA's receivable impairment - 32 - -Deletion of PPE activation in operating expenses - 2 - 1Deletion of provision in hydros - 5 - 2CTEB's EBITDA, at our 50% ownership 39 41 15 16 Adjusted EBITDA from power generation 362 304 120 112 Adjusted EBITDA for the power generation segment was US$120 million (+8% vs. Q3 24, +7% vs. Q2 25), supported by gas self-management during winter, PEPE 6’s contribution and the additional seasonal remuneration for spot open-cycle capacity, partially offset by reduceddispatch. Adjusted EBITDA excludes non-operating, non-recurrent and non-cash items and considers CTEB’s 50% ownership, which posted US$15million in Q3 25 (flat vs. Q3 24, +74% vs. Q2 25). The additional spot capacity remuneration and higher industrial sales explain the quarter-on-quarterimprovement in EBITDA. Finally, excluding CTEB, capital expenditures totaled US$18 million in Q3 25, down from US$24 million in Q3 24, mainly allocated tomaintenance. Earnings release Q3 25 ● 10
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2.3 Analysis of the petrochemicals segment Petrochemicals segment, consolidatedFigures in US$ million Nine-month period Third quarter 2025 2024 ∆% 2025 2024 ∆% Sales revenue 329 394 -16% 115 140 -18% Domestic sales 190 247 -23% 59 92 -35% Foreign market sales 139 147 -5% 56 48 +15% Cost of sales (319) (361) -12% (113) (135) -16% Gross profit 10 33 -70% 2 5 -60% Selling expenses (9) (9) - (3) (3) - Administrative expenses (5) (5) - (2) (2) - Other operating income 19 11 +73% - 3 -100% Other operating expenses (8) (5) +60% (3) (2) +50% Operating income 7 25 -72% (6) 1 NA Finance income 27 - NA - - NA Finance costs - (3) -100% - (1) -100% Other financial results 4 4 - 1 3 -67% Financial results, net 31 1 NA 1 2 -50% Profit before tax 38 26 +46% (5) 3 NA Income tax (11) 7 NA 3 4 -25% Net income for the period 27 33 -18% (2) 7 NA Adjusted EBITDA (6) 28 NA (5) 2 NA Increases in PPE 14 4 +250% 8 1 NA Depreciation and amortization 4 3 +33% 1 1 - Reconciliation of adjusted EBITDA from petrochemicals,in US$ million Nine-month period Third quarter 2025 2024 2025 2024 Consolidated operating income 7 25 (6) 1Consolidated depreciations and amortizations 4 3 1 1 Reporting EBITDA 11 28 (5) 2 Deletion of gain from commercial interests (0) (0) (0) (0)Deletion of contingencies adjustment (17) - - - Adjusted EBITDA from petrochemicals (6) 28 (5) 2 The adjusted EBITDA for the petrochemicals segment recorded a US$5 million loss in Q3 25, compared to the US$2 million profit in Q3 24,mainly due to weaker domestic demand for styrene and octane bases, lower international reference prices and, to a lesser extent, the temporary outageof the polystyrene plant and a non-recurrent US$3 million gain recorded in Q3 24 from exports settlements at a differential FX. These effects werepartially offset by higher exports of reforming products and lower raw material costs. The drop in EBITDA compared to Q2 25 is mainly due to lowerreforming margins from processing imported virgin naphtha and softer domestic demand for octane bases. The total volume sold reached 122 thousand tons (-4% vs. Q3 24, -2% vs. Q2 25), mainly explained by lower domestic demand, partiallyoffset by higher exports of aromatics and styrene. Financial results recorded a profit of US$1 million in Q3 25 (-50% vs. Q3 24, -75% vs. Q2 25), mainly due to derivatives losses. Finally, capital expenditures totaled US$8 million in Q3 25, up from US$1 million in Q3 24, mainly allocated to maintenance. Earnings release Q3 25 ● 11
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Petrochemicals'key performance indicators Products Total Styrene & polystyrene1 SBR Reforming & others Nine-month period Volume sold 2025 (thousand ton) 62 31 238 331Volume sold 2024 (thousand ton) 64 33 251 349Variation 2025 vs. 2024 -4% -8% -5% -5% Average price 2025 (US$/ton) 1,514 1,679 770 993Average price 2024 (US$/ton) 1,804 1,841 861 1,128Variation 2025 vs. 2024 -16% -9% -11% -12% Third quarter Volume sold Q3 25 (thousand ton) 20 11 91 122Volume sold Q3 24 (thousand ton) 22 11 94 128Variation Q3 25 vs. Q3 24 -10% -3% -3% -4% Average price Q3 25 (US$/ton) 1,496 1,561 741 937Average price Q3 24 (US$/ton) 1,825 1,926 822 1,092Variation Q3 25 vs. Q3 24 -18% -19% -10% -14% Note: 1 Includes Propylene. 2.4 Analysis of the holding and others segment Holding and others segment, consolidatedFigures in US$ million Nine-month period Third quarter 2025 2024 ∆% 2025 2024 ∆% Sales revenue 18 29 -38% 6 19 -68%Cost of sales - (5) -100% - (5) -100% Gross profit 18 24 -25% 6 14 -57% Selling expenses (1) - NA - - NAAdministrative expenses (35) (38) -8% (15) (19) -21%Other operating income 8 4 +100% 3 3 -Other operating expenses (29) (34) -15% (7) (6) +17%Income from the sale of associates - 7 -100% - - NAResults for participation in joint businesses 94 129 -27% 27 52 -48% Operating income 55 92 -40% 14 44 -68% Finance costs (38) (24) +58% (19) (9) +111%Other financial results 77 25 +208% 38 18 +111%Financial results, net 39 1 NA 19 9 +111% Profit before tax 94 93 +1% 33 53 -38% Income tax 8 (12) NA (5) (5) - Net income for the period 102 81 +26% 28 48 -42% Adjusted EBITDA 125 112 +11% 36 43 -16% Increases in PPE 7 4 +83% 3 2 +26%Depreciation and amortization - - NA - - NA The holding and others segment, excluding equity income from affiliates TGS and Transener, posted a loss on operating margin of US$13million in Q3 25, compared to a US$8 million loss in Q3 24, mainly explained by higher labor costs and increased third-party service fees, as well as theabsence of OCP Ecuador, which had contributed US$8 million of operating income during its short consolidation in Q3 24. These effects were partiallyoffset by higher income fee. Financial results showed a net profit of US$19 million (+111% vs. Q3 24, +46% vs. Q2 25), mainly reflecting FX gains from the sharper AR$devaluation over the net liability position in that currency, partially offset by higher interest expenses from tax liabilities. Earnings release Q3 25 ● 12
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Reconciliation of adjusted EBITDA from holding and others,in US$ million Nine-month period Third quarter 2025 2024 2025 2024 Consolidated operating income 55 92 14 44Consolidated depreciations and amortizations - - - - Reporting EBITDA 55 92 14 44 Deletion of equity income (94) (129) (27) (52)Deletion of gain from commercial interests - (0) - (0)Deletion of contigencies provision - 16 - -Deletion of the sale of associates - (7) - -Deletion of arbitration costs in OCP 8 - - -TGS's EBITDA adjusted by ownership 115 113 36 40Transener's EBITDA adjusted by ownership 41 26 14 11 Adjusted EBITDA from holding and others 125 112 36 43 The adjusted EBITDA from our holding and others segment excludes non-operating, non-recurring, and non-cash items and includes EBITDAadjusted for equity ownership in TGS and Transener. In Q3 25, the US$36 million profit (-16% vs. Q3 24, +3% vs. Q2 25) was mainly due to highercorporate expenses and a lower contribution from TGS, partially offset by Transener’s performance. At TGS, the EBITDA adjusted for our stake was US$36 million in Q3 25, compared to US$40 million in Q3 24, explained by lower regulatedmargins, as the 5% tariff increase during Q3 25 lagged behind 6% inflation and 15% AR$ devaluation, partially offset by higher exports of NGL andethane sold domestically. At Transener, the EBITDA adjusted for our stake was US$14 million in Q3 25, up from US$11 million in Q3 24, supported by a 19% tariff hikethat outpaced both inflation (6%) and devaluation (15%). Earnings release Q3 25 ● 13
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3. Cash and financial borrowings As of September 30, 2025,in US$ million Cash1 Financial debt Net debt Consolidatedin FS Ownershipadjusted Consolidatedin FS Ownershipadjusted Consolidatedin FS OwnershipadjustedPower generation 881 873 444 444 (437) (429) Petrochemicals 0 0 - - (0) (0) Holding and others - - - - - - Oil and gas - - 1,311 1,311 1,311 1,311 Total under IFRS/Restricted Group 881 873 1,755 1,755 874 882 Affiliates at O/S2 198 198 244 244 46 46 Total with affiliates 1,079 1,071 1,999 1,999 920 928 Note: Financial debt includes accrued interest. 1 It includes cash and cash equivalents, financial assets at fair value with changing results, and investments at amortized cost. 2 Under IFRS, theaffiliates CTBSA, Transener and TGS are excluded from Pampa’s consolidated figures. 3.1 Debt transactions During Q3 25, Pampa issued CB Series 25 for US$105 million, maturing on a bullet basis on August 6, 2028, with a semiannual fixed rate of7.25%. In addition, Pampa obtained export pre-financing, net of payments, for US$50 million. As of September 30, 2025, Pampa’s financial debt under IFRS totaled US$1,755 million, 16% lower than at year-end 2024. This decrease ismainly due to the early redemption of the 2027 and 2029 Notes, funded with proceeds from the issuance of the 2034 Notes. However, net debtincreased to US$874 million, driven by higher capital expenditures in Rincón de Aranda, share buybacks and increased collateral requirements related tothe crude oil price hedge. After the quarter’s closing, US$47 million of the export pre-financing was repaid, and OCP Ecuador’s guarantees were released for US$84million. Therefore, net debt decreased to US$790 million and the net leverage ratio down to 1.1x. As of September 30, 2025, 92% of total gross debt consisted of securities issued in capital markets, while the remaining 8% corresponded tobank financing. The gross debt principal breakdown is shown below: Type of debt CurrencyLegislation Amountin million US$ % overtotal gross debtAverage rateAverage life Call AR$ Argentine 0.1 0% 45% 0.0Exports pre-financing US$ Argentine 50 3% 7% 0.2Loans US$ Argentine 85 5% 5% 1.3 CB US$ MEP Argentine 140 8% 5% 1.8US$ Argentine 156 9% 7% 2.1US$-link Argentine 87 5% 0% 2.2US$ Foreign 1,230 70% 8% 7.3 Total 1,747 100% 5.6 US$ 1,660 95% 7.5% 5.8 AR$ 87 5% 0.1% 2.2 Through proactive liability management, Pampa continued to strengthen its debt profile, extending the average maturity to 5.6 years. The chartbelow shows the principal maturity profile, net of repurchases, in US$ million by the end of Q3 25: Earnings release Q3 25 ● 14
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Note : The chart only considers Pampa’s consolidated figures under IFRS andexcludes affiliates TGS, Transener, and CTBSA. The cash position includes cash andcash equivalents, financial assets at fair value with changing results, andinvestments at amortized cost. Regarding our affiliates, CTEB cancelled bank borrowings for US$15 million, while TGS extended debt maturities by US$26 million and obtainednew loans for US$19 million. As of today, Pampa remains in full compliance with all debt covenants. 3.2 Summary of debt securities CompanyIn US$ million Security MaturityAmountissued Amountnet of repurchasesCoupon In US$-Foreign Law Pampa CB Series 9 at par & fixed rate 2026 293 120 9.5%CB Series 21 at discount & fixed rate 2031 410 410 7.95%CB Series 23 at discount & fixed rate 2034 700 700 7.875% TGS1 CB at discount at fixed rate 2031 490 490 8.5% In US$-Argentine Law Pampa CB Series 20 2026 108 51 6%CB Series 25 2028 105 105 7.25% In US$-link Pampa CB Series 13 2027 98 87 0% CTEB1 CB Series 9 2026 50 40 0% In US$-MEP Pampa CB Series 16 2025 56 56 4.99%CB Series 22 2028 84 84 5.75% Note: 1 Under IFRS, affiliates are not consolidated in Pampa’s FS. 3.3 Credit ratings Company Agency Rating Global Local Pampa S&P B-, bb- (stand-alone) naMoody's B2 na FitchRatings B- AAA (long-term)1 A1+ (short-term)1 TGS S&P B-, b+ (stand-alone) naFitchRatings B- na Transener FitchRatings na A+ (long-term)1 CTEB FitchRatings na AA+1 Note: 1 Issued by FIX SCR. Earnings release Q3 25 ● 15
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4. Appendix 4.1 Analysis of the nine-month period, by subsidiary and segment SubsidiaryIn US$ million Nine-month period 2025 Nine-month period 2024 % PampaAdjustedEBITDA Net debt2 Net income3 % PampaAdjustedEBITDA Net debt2 Net income3 Oil & gas segment Pampa Energía 100.0% 298 1,311 (38) 100.0% 310 1,029 71 Subtotal oil & gas 298 1,311 (38) 310 1,029 71 Power generation segment Diamante 61.0% 6 (0) 3 61.0% 2 (0) 0Los Nihuiles 52.0% (2) (0) (3) 52.0% (2) (0) (1)VAR 100.0% 12 (0) 3 100.0% 14 (0) 9 CTBSA 77 160 10 81 203 (56)Non-controlling stake adjustment (39) (80) (5) (41) (101) 28Subtotal CTBSA adjusted by ownership 50.0% 39 80 5 50.0% 41 101 (28) Pampa stand-alone, other companies, & adj.1 307 (437) 117 249 (419) 347 Subtotal power generation 362 (357) 125 304 (317) 328 Petrochemicals segment Pampa Energía 100.0% (6) (0) 27 100.0% 28 - 33 Subtotal petrochemicals (6) (0) 27 28 - 33 Holding & others segment Transener 154 (61) 92 100 (68) 47Non-controlling stake adjustment (113) 45 (68) (74) 50 (34)Subtotal Transener adjusted by ownership 26.3% 41 (16) 24 26.3% 26 (18) 12 TGS 437 (65) 199 436 (92) 229Non-controlling stake adjustment (322) 47 (147) (323) 68 (170)Subtotal TGS adjusted by ownership 26.9% 115 (17) 52 25.9% 113 (24) 59 Pampa stand-alone, other companies, & adj.1 (31) - 25 (28) (71) 9 Subtotal holding & others 125 (34) 102 112 (113) 81 Deletions - (46) - - (60) - Total consolidated 779 874 216 754 539 513At our share ownership 777 928 216 754 604 513 Note: 1 The deletion corresponds to other companies or inter-companies. 2 Net debt includes holding companies. 3 Attributable to the Company’s shareholders. Earnings release Q3 25 ● 16
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4.2 Analysis of the quarter, by subsidiary and segment SubsidiaryIn US$ million Q3 25 Q3 24 % PampaAdjustedEBITDA Net debt3 Net income4 % PampaAdjustedEBITDA Net debt3 Net income4 Oil & gas segment Pampa Energía 100.0% 171 1,311 (9) 100.0% 122 1,029 (4) Subtotal oil & gas 171 1,311 (9) 122 1,029 (4) Power generation segment Diamante 61.0% 2 (0) 32 61.0% (0) (0) 0Los Nihuiles 52.0% (1) (0) (3) 52.0% (1) (0) 0VAR 100.0% 4 (0) 32 100.0% 4 (0) 2 CTBSA 30 160 (4) 31 203 26Non-controlling stake adjustment (15) (80) 2 (16) (101) (13)Subtotal CTBSA adjusted by ownership 50.0% 15 80 (2) 50.0% 16 101 13 Pampa stand-alone, other companies, & adj.2 101 (437) (53) 93 (419) 80 Subtotal power generation 120 (357) 6 112 (317) 95 Petrochemicals segment Pampa Energía 100.0% (5) (0) (2) 100.0% 2 - 7 Subtotal petrochemicals (5) (0) (2) 2 - 7 Holding & others segment Transener 52 (61) 31 43 (68) 20Non-controlling stake adjustment (38) 45 (23) (31) 50 (14)Subtotal Transener adjusted by ownership 26.3% 14 (16) 8 26.3% 11 (18) 5 TGS 132 (65) 71 155 (92) 62Non-controlling stake adjustment (97) 47 (52) (115) 68 (46)Subtotal TGS adjusted by ownership 26.9% 36 (17) 19 25.9% 40 (24) 16 Pampa stand-alone, other companies, & adj.2 (13) - 1 (8) (71) 27 Subtotal holding & others 36 (34) 28 43 (113) 48 Deletions - (46) - - (60) - Total consolidated 322 874 23 279 539 146At our share ownership 322 928 23 279 604 146 Note: 1 The deletion corresponds to other companies or inter-companies. 2 Net debt includes holding companies. 3 Attributable to the Company’s shareholders. Earnings release Q3 25 ● 17
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4.3 Consolidated balance sheet In US$ million As of 9.30.2025 As of12.31.2024ASSETS Property, plant and equipment 3,053 2,607Intangible assets 89 95Right-of-use assets 43 11Deferred tax asset 21 157Investments in associates and joint ventures 1,000 993Financial assets at fair value through profit and loss 32 27Trade and other receivables 48 75 Total non-current assets 4,286 3,965 Inventories 256 223Financial assets at amortized cost - 80Financial assets at fair value through profit and loss 470 850Derivative financial instruments 30 1Trade and other receivables 784 488Cash and cash equivalents 411 738 Total current assets 1,951 2,380 Total assets 6,237 6,345 EQUITY Share capital 36 36Share capital adjustment 191 191Share premium 516 516Treasury shares adjustment 1 1Treasury shares cost (23) (7)Legal reserve 44 44Voluntary reserve 2,399 1,657Other reserves (13) (13)Other comprehensive income 100 119Retained earnings 182 742 Equity attributable to owners of the company 3,433 3,286 Non-controlling interest 9 9 Total equity 3,442 3,295 LIABILITIES Provisions 107 137Income tax and minimum notional income tax provision 317 75Deferred tax liability 67 49Defined benefit plans 29 30Borrowings 1,473 1,373Trade and other payables 75 84 Total non-current liabilities 2,068 1,748 Provisions 7 10Income tax liability 15 257Tax liabilities 36 30Defined benefit plans 5 7Salaries and social security payable 31 39Borrowings 282 706Trade and other payables 351 253 Total current liabilities 727 1,302 Total liabilities 2,795 3,050 Total liabilities and equity 6,237 6,345 Earnings release Q3 25 ● 18
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4.4 Consolidated income statement In US$ million Nine-month period Third quarter 2025 2024 2025 2024 Sales revenue 1,491 1,441 591 540 Domestic sales 1,207 1,207 457 465Foreign market sales 284 234 134 75Cost of sales (1,000) (930) (375) (365) Gross profit 491 511 216 175 Selling expenses (69) (57) (26) (21)Administrative expenses (131) (139) (47) (56)Other operating income 85 116 32 33Other operating expenses (62) (72) (22) (20)Impairment of financial assets (5) (56) (3) -Impairment on PPE, int. assets & inventories (8) (19) (7) (19)Results for part. in joint businesses & associates 101 101 25 62Income from the sale of associates - 7 - - Operating income 402 392 168 154 Financial income 42 4 7 2Financial costs (151) (137) (52) (43)Other financial results 137 114 15 40Financial results, net 28 (19) (30) (1) Profit before tax 430 373 138 153 Income tax (214) 140 (115) (7) Net income for the period 216 513 23 146Attributable to the owners of the Company 216 513 23 146Attributable to the non-controlling interest - - - - Net income per share to shareholders 0.2 0.4 0.0 0.1Net income per ADR to shareholders 4.0 9.4 0.4 2.7 Average outstanding common shares1 1,360 1,360 1,360 1,360 Outstanding shares by the end of period1 1,360 1,360 1,360 1,360 Note: 1 It considers the Employee stock-based compensation plan shares, which amounted to 3.9 million common shares as of September 30, 2024 and 2025. Earnings release Q3 25 ● 19
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4.5 Consolidated cash flow statement In US$ million Nine-month period Third quarter 2025 2024 2025 2024OPERATING ACTIVITIES Profit of the period 216 513 23 146Adjustments to reconcile net profit to cash flows from operating activities 407 140 244 93Changes in operating assets and liabilities (133) (367) 76 (17)Increase in trade receivables and other receivables (219) (458) 35 (26)Increase in inventories (34) (33) (14) (3)Increase in trade and other payables 94 80 29 (1)Increase in salaries and social security payables 2 15 12 12Defined benefit plans payments (2) (2) (1) (1)Increase in tax liabilities 25 34 12 4Decrease in provisions (7) (3) (3) (2)Collection for derivative financial instruments, net 8 - 6 - Net cash generated by (used in) operating activities 490 286 343 222 INVESTING ACTIVITIES Payment for property, plant and equipment acquisitions (751) (350) (307) (90)Payment for intangible assets acquisitions - - - 3Collection for sales (Payment for purchases) of public securities and shares, net 376 (26) 60 (112)Recovery (Suscription) of mutual funds, net 11 (1) 15 -Capital integration in companies (41) - - 23Payment for companies´acquisitions - (48) - (48)Payment for right-of-use - - - 13Collection for equity interests in companies sales 1 18 1 -Collection for joint ventures´ share repurchase - 37 - -Collections for intangible assets sales 9 - 6 -Dividends collection 25 8 25 -Collection for equity interests in areas sales 2 - - -Cash addition for purchase of subsidiary - 71 - 71 Net cash generated by (used in) investing activities (368) (291) (200) (140) FINANCING ACTIVITIES Proceeds from borrowings 554 710 174 404Payment of borrowings (128) (94) (20) (25)Payment of borrowings interests (122) (118) (21) (35)Repurchase and redemption of corporate bonds (726) (329) (1) (254)Payment for treasury shares acquisition (16) - (16) -Payments of leases (11) (3) (9) (1) Net cash (used in) generated by financing activities (449) 166 107 89 (Decrease) Increase in cash and cash equivalents (327) 161 250 171 Cash and cash equivalents at the beginning of the period 738 171 161 161(Decrease) Increase in cash and cash equivalents (327) 161 250 171 Cash and cash equivalents at the end of the period 411 332 411 332 Earnings release Q3 25 ● 20
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4.6 Power generation’s main operational KPIs by plant Powergeneration'skeyperformanceindicators Wind Hydroelectric Subtotalhydro+wind Thermal Total PEPE2PEPE3PEPE4PEAPEPE6 HINISAHIDISAHPPL CTLLCTG CTPCPBCTPPCTIWCTGEBAEco-EnergíaCTEB1Subtotalthermal Installedcapacity(MW) 53 53 81 100140 265 388285 1,36578036130 6201001001,25414 8484,107 5,472 Newcapacity(MW) 53 53 81 100140 - - - 428 184100 - - 100100 566 14 2791,344 1,772 Market share 0.1%0.1%0.2%0.2%0.3% 0.6%0.9%0.6% 3.1%1.8%0.8%0.1%1.4%0.2%0.2%2.9%0.03%1.9%9.4% 12% Nine-monthperiod Netgeneration2025 (GWh) 149178267226424 195366466 2,2703,24820731 4391141006,500393,13013,806 16,077 Marketshare 0.1%0.2%0.2%0.2%0.4% 0.2%0.3%0.4% 2.1%3.0%0.2%0.0%0.4%0.1%0.1%6.0%0.0%2.9%12.8% 15.0% Sales 2025(GWh) 159178267226424 195366466 2,2813,23837931 4391141006,850913,13614,376 16,657 Netgeneration2024 (GWh) 139144253231 72 569 413659 2,4803,77921943 2401251036,32454 3,57914,467 16,947 Variation2025 vs.2024 +7%+23%+6%-2%na -66%-11%-29% -8%-14%-6%-29%+83%-9%-3%+3%-28%-13%-5% -5% Sales 2024(GWh) 147144253231 69 569 413659 2,4853,73247343 2401251036,6441153,57915,054 17,539 Avg. price2025(US$/MWh) 93 63 63 79 63 18 30 18 48 30 83 66 76 na na 37 40 33 40 41 Avg. price2024(US$/MWh) 81 64 64 82 64 14 22 12 34 20 52 27 97 na na 36 38 30 35 35 Avg. grossmargin 2025(US$/MWh)50 54 54 54 55 (2) 19 7 34 18 38 30 41 na na 20 14 26 24 26 Avg. grossmargin 2024(US$/MWh) 56 65 65 63 60 4 10 4 25 17 21 1 19 na na 19 11 25 22 22 Thirdquarter NetgenerationQ3 25(GWh) 52 62 90 71 145 31 94 124 6691,28818 6 41 25 19 2,024181,3124,752 5,421 Marketshare 0.1%0.2%0.2%0.2%0.4% 0.1%0.2%0.3% 1.7%3.3%0.0%0.0%0.1%0.1%0.0%5.2%0.0%3.4%12.1% 13.8% Sales Q3 25(GWh) 60 62 90 71 145 31 94 124 6771,27872 6 41 25 19 2,118361,3124,908 5,585 Netgeneration Q324 (GWh) 53 52 89 73 69 152 98 290 8771,37041 6 69 38 36 2,15519 1,3405,074 5,951 VariationQ3 25 vs.Q3 24 -3%+20%+1%-2%#### -80%-4%-57% -24%-6%-57%-2%-41%-32%-47%-6% -4%-2%-6% -9% Sales Q3 24(GWh) 59 52 89 73 67 152 98 290 8801,370123 6 69 38 36 2,26039 1,3405,280 6,161 Avg. priceQ3 25(US$/MWh) 95 62 62 79 62 25 36 20 54 35 na 106na na na 39 41 29 42 43 Avg. price Q324(US$/MWh) 86 64 64 82 64 18 30 13 38 20 75 71 132na na 38 37 29 35 36 Avg. grossmargin Q325(US$/MWh) 51 52 52 60 53 (13)22 5 37 18 63 47 127na na 21 19 24 25 27 Avg. grossmargin Q3 24(US$/MWh)48 50 50 60 59 5 11 5 25 16 34 17 51 na 138 19 1 24 22 23 Note: Gross margin before amortization and depreciation. 1 Co-operated by Pampa (50% equity stake). Earnings release Q3 25 ● 21
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4.7 Production in the main oil and gas blocks In kboe/day at ownership Nine-month period Third quarter 2025 2024 Variation 2025 2024 Variation Gas El Mangrullo 41.2 48.3 -15% 41.2 47.0 -12%Sierra Chata 24.8 19.0 +31% 31.0 23.4 +33%Río Neuquén 8.1 9.5 -15% 7.9 9.8 -20% Rincón del Mangrullo1 1.0 1.3 -22% 0.9 1.1 -21% Others 1.0 0.8 +32% 1.2 0.8 +54% Total gas at working interest 76.0 78.8 -4% 82.2 82.1 +0% Oil Rincón de Aranda 6.9 0.9 na 14.4 1.2 na El Tordillo2 1.5 1.6 -8% 1.6 1.6 -4% Associated oil3 1.1 1.3 -17% 1.2 1.3 -8% Los Blancos 0.1 0.2 -64% 0.1 0.2 -60% Gobernador Ayala4 - 1.1 -100% - 1.0 -100% Total oil at working interest 9.6 5.0 +89% 17.3 5.4 +220% Total 85.5 83.8 +2% 99.5 87.5 +14% Note: Production in Argentina. 1 It does not include shale formation. 2 Pampa transferred the 35.67% stake in the concession to Crown Point Energía in October 2025, including the LaTapera – Puesto Quiroga block. 3 From gas fields. 4 In October 2024, Pampa transferred its 22.51% stake in the concession to Pluspetrol. Earnings release Q3 25 ● 22
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5. Glossary of terms ADR/ADS: American Depositary Receipt AR$: Argentine pesos Bbl: Barrel Boe: Barrels of oil equivalent ByMA: Bolsas y Mercados Argentinos or Buenos Aires Stock Exchange CAMMESA: Compañía Administradora del Mercado Mayorista Eléctrico S.A.or Argentine Wholesale Electricity Market Clearing Company CB/Notes: Corporate Bonds 2027 Notes: Corporate Bonds maturing in 2027 2029 Notes: Corporate Bonds maturing in 2029 2034 Notes: Corporate Bonds maturing in 2034 CCGT: Combined cycle CPB: Piedra Buena Thermal Power Plant CTBSA: CT Barragán S.A. CTEB: Ensenada Barragán Thermal Power Plant CTG: Güemes Thermal Power Plant CTGEBA: Genelba Thermal Power Plant CTIW: Ingeniero White Thermal Power Plant CTLL: Loma De La Lata Thermal Power Plant CTP: Piquirenda Thermal Power Plant CTPP: Parque Pilar Thermal Power Plant DNU: Emergency Executive Order E&P: Exploration and Production EBITDA: Earnings before interest, tax, depreciation and amortization EcoEnergía: EcoEnergía Co-Generation Power Plant ENARGAS: Ente Nacional Regulador del Gas or National Gas RegulatoryEntity ENARSA: Energía Argentina S.A. ENRE: Ente Nacional Regulador de la Electricidad or National ElectricityRegulatory Entity FRA: Adjusted Rent Factor FS: Financial Statements FX: Nominal exchange rate GPM, former GPNK: Francisco Pascasio Moreno Gas Pipeline, formerlyPresident Nestor Kirchner GSA: Long-term gas sale agreement GT: Gas turbine GWh: Gigawatt-hour HIDISA: Diamante Hydro Power Plant HINISA: Los Nihuiles Hydro Power Plant HPPL: Pichi Picun Leufu Hydro Power Plant IFRS: International Financial Reporting Standards Kb/kboe: Thousands of barrels/thousand barrels of oil equivalent Kbpd/kboepd: Thousands of barrels per day/thousand barrels of oilequivalent per day M3: Cubic meter Mboe: Million barrels of oil equivalent MBTU: Million British Thermal Units Mcmpd: Million cubic meters per day MECON: Ministry of Economy MW/MWh: Megawatt/Megawatt-hour N.a.: Not applicable NGL: Natural gas liquids O/S: Share ownership OCP Ecuador: Oleoducto de Crudos Pesados S.A. Pampa / The Company: Pampa Energía S.A. PEA: Arauco II Wind Farm, stages 1 and 2 PEPE: Pampa Energía Wind Farm Plan Gas: Argentine Natural Gas Production Promotion Plan, 2020–2024Supply and Demand Scheme (DNU No. 892/20, 730/22 and supplementaryprovisions) PPA: Power purchase agreement PPE: Property, plant and equipment Q2 25: Second quarter of 2025 Q3 25/Q3 24: Third quarter of 2025/Third quarter of 2024 Res.: Resolution/Resolutions RMA: Adjusted Marginal Rent SE: Secretariat of Energy ST: Steam turbine TGS: Transportadora de Gas del Sur S.A. Ton: Metric ton TPF: Temporary processing facility Transba: Empresa de Transporte de Energía Eléctrica por DistribuciónTroncal de la Provincia de Buenos Aires Transba S.A. Transener: Compañía de Transporte de Energía Eléctrica en Alta TensiónTransener S.A. US$: US Dollars US$-link: A security in which the underlying is linked to a US$ wholesaleexchange rate US$-MEP: A security in which the settlement uses US$ in the domesticmarket WEM: Wholesale electricity market Earnings release Q3 25 ● 23