Q4 25 Earnings release

Earnings Release Q4 25

Stock information

Share capital net of repurchases as of February 27, 2026:

1,343.6 million common shares/

53.7 million ADS

Market capitalization: AR$6,039 billion/ US$4,180 million

Information about the videoconference

Date and time:

Monday, March 2

4.30 PM Eastern Standard Time

6.30 PM Buenos Aires Time

Access link:

bit.ly/Pampa4Q2025VC

For further information about Pampa

Email

investor@pampa.com

Website for investors

ri.pampa.com/en

Argentina's Securities and Exchange Commission https://www.argentina.gob.ar/cnv

US Securities and Exchange Commissionsec.gov

Buenos Aires, March 2, 2026

‌Basis of presentation

Pampa reports its financial information in US$, its functional currency. For local currency equivalents, transactional FX is applied. However, Transener and TGS's figures are adjusted for inflation as of December 31, 2025, and converted into US$ using the period-end FX. Previously reported figures remained unchanged.

‌Q4 25 main results1

Q4 25 was marked by sustained shale oil growth at Rincón de Aranda and strong performance across our thermal power plants.

Oil and gas Production (kboe/day) 81.2 61.6 +32%

Note: * Price net of export duty and quality/logistic discounts.

recognition of a non-cash deferred income tax credit, as inflation outpaced the AR$ devaluation during Q4 25, offset by weaker net financial results.

Net debt decreased to US$801 million as of December 2025, compared to US$874 million as of September 2025, reflecting solid free cash flow generation and reduced collateral requirements.

‌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, and includes affiliates' EBITDA at our ownership. Further information on section 3.1.

1. ‌Relevant events
   1. ‌Oil & gas ‌Reserves report as of December 31, 2025

      As of December 31, 2025, Pampa's proven reserves (P1) totaled 296 mboe, a 28% increase from 231 mboe at year-end 2024. This growth was mainly driven by a significant expansion of shale reserves in Vaca Muerta, supported by an intensified drilling and completion program. Rincón de Aranda was the main growth engine (+352%/+43.7 mboe year-on-year), followed by Sierra Chata (+41%/+28 mboe year-on-year), partially offset by El Mangrullo, where no new wells were drilled or tied-in (-5%/-4.7 mboe year-on-year).

      As a result, certified P1 shale reserves grew 54% to 204 mboe in 2025, representing 69% of Pampa's total P1 reserves (vs. 57% as of December 2024). 81% of total proven reserves correspond to natural gas, and 19% to crude oil.

      In 2025, the reserve replacement ratio was 3.2x, reflecting that additions significantly outpaced the period's rising production. The average reserve life extended from 8.6 years as of December 2024 to 10.2 years at year-end 2025.

      Proven reserves (P1) in Argentina, in mboe	Crude oil, condensed and NGL	Natural gas	Total
      Proven developed (P1-D)	24.0	135.7	159.7
      Proven undeveloped (P1-U)	33.0	103.2	136.1
      Total as of December 31, 2025	57.0	238.9	295.8
      % shale	92%	64%	69%
      Total as of December 31, 2024	17.2	214.0	231.2
      % shale	68%	56%	57%

      As of December 31, 2025, Pampa had 470 producing wells, compared to 688 at the end of 2024. This decrease is explained by the divestment of the El Tordillo and La Tapera-Puesto Quiroga blocks, partially offset by increased activity in Rincón de Aranda, which had 28 producing wells, and 150 wells in the Río Neuquén block.

      Pampa's total proven reserves

      As of December 31, 2025

      100% = 296 million boe

      Evolution of Pampa's certified proven reserves In million boe

      
      
      ‌Pass-through of Plan Gas contracts

      In December 2025, the SE established guidelines for the pass-through of Plan Gas volumes by producers holding GSAs with CAMMESA and/or ENARSA, in line with Res. SE No. 400/2025 (Res. No. 501/25). On December 12, 2025, Pampa requested CAMMESA to assign up to 4.9 mcmpd of gas corresponding to Round 1, together with the full volumes awarded under Round 3. On December 30, CAMMESA, in its capacity as operator of thermal generation units in the WEM, approved the request.

      Furthermore, the SE introduced amendments to the Plan Gas GSA applicable for producers that agree to pass through supply contracts with ENARSA, as offtaker, to distribution companies and CAMMESA (Res. No. 606/25). ENARSA will define and oversee the procedures and volume allocation.

      Producers adhering to this scheme will receive 90% of the Government compensation, subject to the submission of an affidavit. The resolution also reduces injection commitments and eliminates the quarterly reporting requirement on investment plan progress (Res. SE No. 36/26). Pampa is currently assessing the implications of this resolution.

      ‌Extension of RIGI and inclusion of upstream hydrocarbons

      On February 19, 2026, the DNU No. 105/26 extended the deadline to adhere to RIGI until July 8, 2027, and incorporated hydrocarbon production in greenfield blocks within the eligible sectoral scope. Only new projects qualify for the regime, including hydrocarbon exploration and production, as well as the development of related treatment, storage, and transportation infrastructure. A minimum investment requirement of US$600 million was set for onshore developments and US$200 million for offshore projects.

      Where RIGI and non-RIGI activities coexist within the same block, beneficiaries must ensure strict financial and corporate ring-fencing, as well as production traceability through separate measurement systems. These activities must be conducted through a dedicated legal vehicle exclusively holding the assets, rights, and operations.

      The development of Rincón de Aranda began following the approval of the RIGI framework for midstream projects. Within that scheme, the original plan contemplated the construction of all associated infrastructure and the required processing plant to reach a plateau of 45 kbpd by 2027. The development capex exceeds US$1.5 billion, representing the largest capital allocation to a single asset in Pampa's history. Subsequently, the inclusion of upstream activities under the RIGI broadened the project's scope, enabling the development of the block's northern area, accelerating the production ramp-up, bringing forward the production target, and extending its duration. As a result, Rincón de Aranda's growth profile is strengthened and enhancing long-term value creation.

   2. ‌Power generation

      Until October 31, 2025, all power generation units without PPAs were remunerated under the regulated scheme established by Res. SE No. 381/25. Effective as of November 1, 2025, all our thermal units without contracts and HINISA transitioned to the new framework defined by Res. SE No. 400/25, which introduced a marginal pricing spot market and the MAT. HIDISA and HPPL continue to operate under the legacy regulated scheme. Since December 2025, Pampa has also been self-supplying natural gas to CTLL and CTGEBA in accordance with the new guidelines set forth in Res. SE No. 400/25.

      ‌Extension of the additional remuneration scheme -Res. SE No. 294/24

      The Res. SE No. 294/24 establishes a temporary additional remuneration scheme aimed at increasing the availability of open-cycle units during peak demand periods, initially effective from December 2024 to March 2026.

      On January 21, 2026, following the submission of the required maintenance plans, CAMMESA confirmed that the SE extended this additional remuneration scheme for CPB, CTG, CTP, CTLL, CTGEBA and EcoEnergía through March 31, 2027 (Notes No. B-183719-1, B-183724-1, B-183727-1, B-183729-1, B-183731-1 and B-183082-1).

      ‌Last updates for the legacy regulated scheme

      Effective as of:	Legacy regulated remuneration scheme
      	Increase	Resolution
      October 2025	0.5%	SE No. 381/25
      November 2025	Thermal: 3.5%; hydro: 12-20%	SE No. 483/25
      December 2025	2.0%	SE No. 602/25
      Cumulative 2025	24.7%
      January 2026	2.0%	SE No. 34/26

   3. ‌Transener and TGS: last tariff updates‌

      Effective as of:	Transener/Transba				TGS
      	Increase	Resolution		Increase	Resolution
      October 2025	7.1%/3.9%	ENRE No. 675 and 676/25		2.7%	ENARGAS No. 732/25
      November 2025	7.6%/4.4%	ENRE No. 724 and 731/25		3.2%	ENARGAS No. 812/25
      December 2025	5.9%/2.7%	ENRE No. 778 and 779/25		1.9%	ENARGAS No. 907/25
      Cumulative 2025	93.5%/47.4%			24.0%
      January 2026	1.9%/1.9%	ENRE No. 823 and 824/25		2.4%	ENARGAS No. 1,000/25
      February 2026	2.5%/2.5%	ENRE No. 28 and 29/26		2.9%	ENARGAS No. 32/26
      March 2026	2.1%/2.1%	ENRE No. 110 and 111/26		2.5%	ENARGAS No. 77/26

2. ‌Analysis of Q4 25 results

   Net Income

   Adjusted EBITDA

   Sales

   Net Income

   Adjusted EBITDA

   Sales

   Net Income

   Adjusted EBITDA

   Sales

   Breakdown by segment

   In US$ million

   Variation

   Q4 24

   Q4 25

   Oil and Gas	204	77	(17)	134	36	(76)	+52%	+111%	-78%
   Power generation	207	111	172	167	86	133	+24%	+28%	+29%
   Petrochemicals	114	1	(23)	122	(7)	39	-7%	NA	NA
   Holding, transport and others	6	42	29	36	67	10	-83%	-38%	+190%
   Eliminations	(24)	-	-	(24)	-	-	+2%	NA	NA
   Total	507	230	161	435	182	106	+16%	+26%	+52%

   Reconciliation of adjusted EBITDA,

   Fiscal year

   Fourth quarter

   Note: Net income is attributable to the Company's shareholders.

   in US$ million	2025	2024	2025	2024
   Consolidated operating income	503	440	101	48
   Consolidated depreciations and amortizations	414	342	109	85
   Reporting EBITDA	917	782	210	133
   Adjustments from oil and gas segment	(8)	40	3	35
   Adjustments from generation segment	(19)	86	(48)	6
   Adjustments from petrochemicals segment	20	(27)	37	(27)
   Adjustments from holding, transport & others segment	98	55	29	35
   Consolidated adjusted EBITDA	1,009	937	230	182
   At our ownership	1,005	935	228	181

   1. ‌Analysis of the oil and gas segment

      Oil & gas segment, consolidated Fiscal year Fourth quarter
      Figures in US$ million	2025	2024	∆%	2025	2024	∆%
      Sales revenue	862	730	+18%	204	134	+52%
      Domestic sales	663	622	+7%	148	110	+34%
      Foreign market sales	199	108	+84%	56	24	+135%
      Cost of sales	(613)	(515)	+19%	(152)	(128)	+19%
      Gross profit	249	215	+16%	52	6	NA
      Selling expenses	(80)	(58)	+38%	(24)	(12)	+100%
      Administrative expenses	(83)	(82)	+1%	(23)	(25)	-8%
      Exploration expenses	-	(21)	-100%	-	(21)	-100%
      Other operating income	49	87	-44%	8	20	-60%
      Other operating expenses	(23)	(28)	-18%	(7)	(6)	+17%
      Impairment of financial assets	(21)	(10)	+110%	(16)	-	NA
      Recovery of impairment (Impairment) of PPE, int. assets and inventories	(3)	(34)	-91%	5	(15)	NA
      Results for participation in joint businesses	3	-	NA	1	-	NA
      Operating income	91	69	+32%	(4)	(53)	- 92%
      Finance income	-	2	-100%	-	1	-100%
      Finance costs	(101)	(96)	+5%	(24)	(25)	-4%
      Other financial results	(35)	(11)	+218%	(10)	6	NA
      Financial results, net	(136)	(105)	+30%	(34)	(18)	+89%
      Loss before tax	(45)	(36)	+25%	(38)	(71)	- 46%
      Income tax	(10)	31	NA	21	(5)	NA
      Net (loss)/income for the period	(55)	(5)	NA	(17)	(76)	- 78%
      Adjusted EBITDA	375	346	+8%	77	36	+111%
      Increases in PPE and right-of-use assets	1,039	354	+194%	320	111	+188%
      Depreciation and amortization	292	237	+23%	78	54	+44%
      Lifting cost	221	180	+23%	59	49	+21%
      Lifting cost per boe	7.2	6.3	+14%	8.0	8.7	-8%

      Sales in the oil and gas segment rose 52% year-on-year, driven by accelerated crude oil production at Rincón de Aranda, increased gas exports to Chile and, to a lesser extent, higher sales to industrial customers. These effects were partially offset by lower Brent prices, which reduced realized crude oil prices, though this was mitigated by hedging instruments in place since April 2025. Gas export prices also declined in line with Brent.

      Regarding the operational performance, total production averaged 81.2 kboepd in Q4 25 (+32% vs. Q4 24, but -18% vs. Q3 25), mainly explained by strong shale oil growth at Rincón de Aranda and higher gas output at Sierra Chata. The quarter-on-quarter decrease was explained by gas seasonality, offset by sustained oil growth.

      Gas production averaged 10.7 mcmpd in Q4 25 (+10% vs. Q4 24, -23% vs. Q3 25). Analyzing the gas output by block, El Mangrullo accounted for 46% of the total gas output at 5.0 mcmpd (-5% vs. Q4 24, -29% vs. Q3 25), followed by Sierra Chata with 4.0 mcmpd following the tie-in of 4 new wells, contributing 38% of the production (+39% vs. Q4 24, -24% vs. Q3 25). Associated gas from Rincón de Aranda continued to ramp up, reaching 0.2 mcmpd (+231% vs. Q3 25). At non-operated blocks, Río Neuquén produced 1.1 mcmpd (-13% vs. Q4 24, -16% vs. Q3 25), while Rincón del Mangrullo and Aguaragüe continued their natural depletion, producing a total of 0.3 mcmpd.

      Oil and gas' key performance indicators	Oil	2025 Gas	Total	Oil	2024 Gas	Total	Oil	Variation Gas	Total
      Fiscal year
      Volume

      Production

      In thousand m3/day	1.9	12,362		0.8	12,478
      In million cubic feet/day		437			441		+145%	-1%	+8%
      In thousand boe/day	11.7	72.8	84.4	4.8	73.4	78.2
      Sales
      In thousand m3/day	1.9	12,390		0.8	12,468
      In million cubic feet/day		438			440		+139%	-1%	+8%
      In thousand boe/day	11.8	72.9	84.8	5.0	73.4	78.3
      Average Price
      In US$/bbl In US$/MBTU	61.5	3.7		70.2	3.7		-12%	-1%
      Fourth quarter
      Volume
      Production
      In thousand m3/day	2.9	10,736		0.6	9,785
      In million cubic feet/day		379			346		+355%	+10%	+32%
      In thousand boe/day	18.0	63.2	81.2	4.0	57.6	61.6
      Sales
      In thousand m3/day	2.7	10,783		0.9	9,897
      In million cubic feet/day		381			350		+212%	+9%	+26%
      In thousand boe/day	16.9	63.5	80.3	5.4	58.3	63.7

      60.9

      67.6

      3.0 2.9

      Average Price

In US$/bbl In US$/MBTU

-10% +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.

The gas price averaged US$3.0 per MBTU in Q4 25 (+4% vs. Q4 24, -33% vs. Q3 25 due to seasonality), supported by improved industry prices, partially offset by lower export prices in line with the drop of Brent and by the impact of AR$ devaluation on retail tariffs, which spread to the GSA price is collected through Plan Gas compensation paid by the Government.

Regarding our gas deliveries by commercial channel during Q4 25, 59% was destined for CAMMESA's thermal generation (vs. 68% in Q4 24) and 13% to retail distribution companies (flat vs. Q4 24), both under Plan Gas GSA. The industrial/spot market represented 13% (vs. 12% in Q4 24), 9% was exported (vs. 3% in Q4 24 due to stronger demand), and the remaining 7% was allocated to intersegment consumption (vs. 4% in Q3 24). Within this channel, 44% was supplied to our petrochemical plants, and 56% was directed mainly to CTLL, following the authorization of fuel self-procurement for power plants under the new WEM framework. After the partial pass-through of Plan Gas GSAs in December 2025, Pampa began vertically integrating fuel supply to CTLL and CTGEBA's CCGTs, both with high load factors. Said integration represented 10% of gas production in December and increased to 29% in January, enhancing margins and operational efficiency.

The average oil price, net of export duty and commercial discounts, was US$60.9 per barrel (-10% vs. Q4 24, flat vs. Q3 25), due to lower Brent prices. Without hedging at Rincón de Aranda, the average oil price would have been US$53.4 per barrel. Exports represented 48% of total volume sold in Q4 25, vs. 41% in Q4 24.

The lifting cost4 totaled US$59 million in Q4 25 (+21% vs. Q4 24, flat vs. Q3 25), explained by higher crude oil treatment costs related to shale oil growth and temporary facilities at Rincón de Aranda, as well as increased gas treatment costs at Sierra Chata. Lower maintenance and labor costs, and the divestment of mature non-operated blocks, offset those effects. The lifting cost per boe decreased 8% to US$8.0 per boe produced in Q4 25 vs. US$8.7 per boe in Q4 24, explained by the rising production at Rincón de Aranda and higher year-on-year gas demand. Compared to Q3 25, the 24% increase in lifting cost per boe reflects the gas seasonality and, to a lesser extent, higher temporary infrastructure costs at Rincón de Aranda.

Excluding depreciation and amortization and lifting costs, other operating costs increased 9% vs. Q4 24 but decreased 23% vs. Q3 25, mainly due to higher transportation costs, royalties and levies linked to increased production, partially offset by lower crude purchases for trading.

Our oil and gas adjusted EBITDA amounted to US$77 million in Q4 25 (+111% vs. Q4 24, -55% vs. Q3 25), mainly driven by shale oil growth, higher gas exports and industrial sales, and lower crude oil purchases and costs from mature blocks. These effects were partially offset by the sale of our non-operator stake in Gobernador Ayala in Q4 24 and by higher crude oil transport and treatment costs. Gas seasonality explains the quarter-on-quarter decrease in EBITDA. The adjusted EBITDA excludes non-recurring and non-cash income and expenses, as well as overdue commercial interests, equity income from affiliates and ENARSA's US$13 million bad debt, and includes a US$6 million adjustment to the rights-of-use amortization, related to the reclassification of temporary processing facility leases as lifting cost.

‌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-use amortization in the cost of sales. Lifting cost does not include amortizations and depreciations.

1. 1. ‌Analysis of the power generation segment

      Power generation segment, consolidated Fiscal year Fourth quarter
      Figures in US$ million	2025	2024	∆%	2025	2024	∆%
      Sales revenue	792	672	+18%	207	167	+24%
      Cost of sales	(450)	(367)	+23%	(131)	(107)	+22%
      Gross profit	342	305	+12%	76	60	+27%
      Selling expenses	(4)	(3)	+33%	(1)	(1)	-
      Administrative expenses	(42)	(52)	-19%	(11)	(13)	-15%
      Other operating income	23	35	-34%	6	1	NA
      Other operating expenses	(11)	(14)	-21%	(2)	(3)	-33%
      Impairment of financial assets	-	(46)	-100%	-	-	NA
      Recovery of impairment of PPE, int. assets and inventories	55	-	NA	55	-	NA
      Results for participation in joint businesses	12	(21)	NA	7	7	-
      Operating income	375	204	+84%	130	51	+155%
      Finance income	18	8	+125%	3	5	-40%
      Finance costs	(46)	(53)	-13%	(10)	(14)	-29%
      Other financial results	168	183	-8%	87	81	+7%
      Financial results, net	140	138	+1%	80	72	+11%
      Profit before tax	515	342	+51%	210	123	+71%
      Income tax	(217)	119	NA	(37)	10	NA
      Net income for the period	298	461	- 35%	173	133	+30%
      Attributable to owners of the Company	297	461	-36%	172	133	+29%
      Attributable to non-controlling interests	1	-	NA	1	-	NA
      Adjusted EBITDA	472	390	+21%	111	86	+28%
      Adjusted EBITDA at our share ownership	469	389	+20%	109	85	+27%
      Increases in PPE and right-of-use assets	66	105	-37%	20	38	-49%
      Depreciation and amortization	116	100	+16%	29	29	-

      In Q4 25, power generation sales increased 24% year-on-year, mainly driven by higher spot remuneration for our thermal units following the implementation of the new WEM framework in November 2025, in addition to a higher load factor at CTGEBA's legacy CCGT, after life-extension works were completed in Q4 24 and, to a lesser extent, the contribution of PEPE 6. These effects were partially offset by a scheduled overhaul at CTGEBA's new CCGT during Q4 25, which is remunerated under a PPA, and by lower fuel recognition, as fuel is now billed as energy under the new scheme. Compared to Q3 25, sales remained flat, driven by higher spot energy prices, offset by seasonally lower demand.

      Within the spot segment, capacity payments for CCGTs averaged US$4.5 thousand per MW-month (+27% vs. Q4 24, -16% vs. Q3 25), reflecting the new WEM guidelines. Moreover, open cycles (GT and ST) averaged US$5.8 thousand per MW-month (+12% vs. Q4 24 and flat vs. Q3 25), supported by higher capacity payments at CPB, which can operate with alternative fuels. Hydros averaged US$2.1 thousand per MW-month (-12% vs. Q4 24, +2% vs. Q3 25), as HIDISA and HPPL were excluded in the new WEM framework. The most significant impact of Res. SE No. 400/25 is reflected in the variable dispatch margins, as the marginal pricing mechanism benefits more efficient units, particularly CCGTs, as well as power units with self-supplied fuel, allowing them to capture higher margins.

      Regarding operational performance, operated power generation increased 3% year-on-year, in line with the national grid's performance. Higher output was driven by CTGEBA's legacy CCGT (+849 GWh), CTLL's CCGT (+214 GWh) and improved wind conditions at the PEPEs (+55 GWh). These effects were partially offset by lower generation at CTGEBA's new CCGT due to programmed maintenance in October 2025 (-465 GWh), the continued outage at HINISA following the January 2025 climate event (-200 GWh), reduced water input at HPPL and scheduled overhaul at HIDISA (-188 GWh), in addition to lower dispatch from our open-cycle units amid softer demand (-130 GWh).

      The average availability of Pampa's operated units reached 91.3% in Q4 25, down from 94.3% in Q4 24 (-287 basis points), mainly impacted by HINISA's forced outage and programmed maintenance at CTGEBA, CTLL and CTG. These variations were partially offset by scheduled overhauls in CTLL and CTGEBA during Q4 24. Thermal availability, however, improved 75 basis points to 93.2% in Q4 25, underscoring the solid operational performance of our thermal assets.

      Power generation's 2025 2024 Variation
      key performance indicators Wind		Hydro	Thermal	Total	Wind	Hydro	Thermal	Total	Wind	Hydro	Thermal	Total
      Installed capacity (MW) 427		938	4,107	5,472	427	938	4,107	5,472	+0%	-	+0%	- 0%
      Contracted capacity (MW)	427	41	1,299	1,767	427	-	1,343	1,769	+0%	na	-3%	- 0%
      Market share (%)	1.0%	2.1%	9.3%	12.4%	1.0%	2.2%	9.5%	12.6%	-0%	-0%	-0%	- 0%
      Fiscal year
      Net generation (GWh)	1,714	1,360	17,950	21,024	1,270	2,363	18,111	21,743	+35%	-42%	-1%	- 3%
      Volume sold (GWh)	1,723	1,361	18,542	21,625	1,280	2,363	18,914	22,557	+35%	-42%	-2%	- 4%
      Average price (US$/MWh)	69	23	42	43	71	15	36	36	-3%	+51%	+18%	+21%
      Average gross margin (US$/MWh)	54	10	24	26	58	6	22	23	-7%	+69%	+10%	+15%
      Fourth quarter
      Net generation (GWh)	470	334	4,143	4,947	431	722	3,644	4,797	+9%	-54%	+14%	+3%
      Volume sold (GWh)	469	334	4,165	4,968	436	722	3,859	5,018	+7%	-54%	+8%	- 1%
      Average price (US$/MWh)	68	25	52	51	71	15	41	40	-4%	+59%	+25%	+28%
      Average gross margin (US$/MWh)	55	11	25	27	50	7	23	23	+9%	+64%	+9%	+16%

      Note: Gross margin before amortization and depreciation. Includes CTEB (co-operated by Pampa, 50% equity stake).

      Excluding depreciation and amortization, net operating costs increased 17% year-on-year to US$110 million in Q4 25, mainly due to higher gas procurement for our thermal generation, partially offset by lower labor and maintenance expenses. Compared to Q3 25, operating expenses increased 11%, mainly driven by gas purchases and, to a lesser extent, higher maintenance and materials costs, partially offset by lower transportation costs following the discontinuation of the Energía Plus B2B segment in late October 2025.

      Other operating income and expenses improved to a US$4 million profit from a US$2 million loss in Q4 24, mainly due to higher insurance recoveries net of repair costs. Financial results in Q4 25 recorded a net profit of US$80 million, 11% higher than the US$72 million in Q4 24, reflecting lower debt interest expense following bond refinancing, partially offset by decreased gains on financial instruments.

      Reconciliation of adjusted EBITDA from power generation, Fiscal year Fourth quarter
      in US$ million	2025	2024	2025	2024
      Consolidated operating income	375	204	130	51
      Consolidated depreciations and amortizations	116	100	29	29
      Reporting EBITDA	491	304	159	80
      Deletion of CTEB's equity income	(12)	21	(7)	(7)
      Deletion of PPE, int. assets and inventories' recovery of impairment	(55)	-	(55)	-
      Deletion of commercial interests to CAMMESA	(5)	(29)	(1)	(1)
      Deletion of CAMMESA's receivable impairment	-	32	-	-
      Deletion of PPE activation in operating expenses	-	3	-	1
      Deletion of provision in hydros	-	6	-	1
      CTEB's EBITDA, at our 50% ownership	53	53	15	13
      Adjusted EBITDA from power generation	472	390	111	86

      Adjusted EBITDA for the power generation segment was US$111 million (+28% vs. Q4 24, -8% vs. Q3 25), supported by improved remuneration for our thermal units under the new WEM framework and lower labor and maintenance costs. These effects were partially offset by increased gas purchases and reduced output at CTGEBA's new CCGT during programmed maintenance. Seasonality explains the 7% quarter-on-quarter decrease in EBITDA. Adjusted EBITDA excludes non-operating, non-recurrent and non-

      cash items and considers CTEB's 50% ownership, which contributed US$15 million in Q4 25 (+16% vs. Q4 24, flat vs. Q3 25).

      Capital expenditures, excluding CTEB, totaled US$20 million in Q4 25, down from US$38 million in Q4 24, mainly allocated to maintenance activities.
   2. ‌Analysis of the petrochemicals segment

      Petrochemicals segment, consolidated Fiscal year Fourth quarter
      Figures in US$ million	2025	2024	∆%	2025	2024	∆%
      Sales revenue	443	516	-14%	114	122	-7%
      Domestic sales	265	326	-19%	75	79	-5%
      Foreign market sales	178	190	-6%	39	43	-8%
      Cost of sales	(429)	(487)	-12%	(110)	(126)	-13%
      Gross profit	14	29	- 52%	4	(4)	NA
      Selling expenses	(12)	(13)	-8%	(3)	(4)	-25%
      Administrative expenses	(6)	(7)	-14%	(1)	(2)	-50%
      Other operating income	19	41	-54%	-	30	-100%
      Other operating expenses	(9)	(7)	+29%	(1)	(2)	-50%
      Impairment of PPE, int. assets and inventories	(37)	-	NA	(37)	-	NA
      Operating income	(31)	43	NA	(38)	18	NA
      Finance income	27	21	+29%	-	21	-100%
      Finance costs	-	(3)	-100%	-	-	NA
      Other financial results	3	7	-57%	(1)	3	NA
      Financial results, net	30	25	+20%	(1)	24	NA
      Profit before tax	(1)	68	NA	(39)	42	NA
      Income tax	5	4	+25%	16	(3)	NA
      Net income for the period	4	72	- 94%	(23)	39	NA
      Adjusted EBITDA	(5)	21	NA	1	(7)	NA
      Increases in PPE	15	6	+150%	1	2	-36%
      Depreciation and amortization	6	5	+20%	2	2	-
      Reconciliation of adjusted EBITDA from petrochemicals, Fiscal year Fourth quarter
      in US$ million			2025	2024	2025		2024
      Consolidated operating income			(31)	43	(38)		18
      Consolidated depreciations and amortizations			6	5	2		2
      Reporting EBITDA			(25)	48	(36)		20
      Deletion of PPE, int. assets and inventories' impairment			37	-	37		-
      Deletion of gain from commercial interests			(0)	(0)	(0)		0
      Deletion of contingencies adjustment			(17)	(27)	-		(27)
      Adjusted EBITDA from petrochemicals			(5)	21	1		(7)
      The adjusted EBITDA for the petrochemicals		segment	posted a US$1	million	profit in Q4 25,
      compared to a US$7 million loss in Q4 24, mainly driven by higher domestic sales in the Reforming, which

      achieved record octane base volumes in December, improved spreads between international and domestic styrenics prices, and lower operating costs. These effects were partially offset by lower styrenics and SBR sales, a decline in international reference prices and, to a lesser extent, the US$2 million extraordinary gain recorded in Q4 24 from export settlements at a differential FX rate. The quarter-on-quarter improvement in EBITDA is mainly due to lower idle capacity and tighter cost management.

      The total volume sold reached 129 thousand tons (+7% vs. Q4 24, +6% vs. Q3 25), mainly driven by increased domestic demand for reforming products, partially offset by softer demand for styrene, polystyrene, and SBR.

      Financial results recorded a loss of US$1 million in Q4 25 (-US$25 million vs. Q4 24, -US$2 million vs. Q3 25), mainly explained by the extraordinary gain recorded in Q4 24, related to the recovery of interest from customs contingencies.

      Petrochemicals'

      Products

      Total

      Finally, capital expenditures totaled US$1 million in Q4 25, compared to US$2 million in Q4 24, mainly allocated to maintenance of facilities.

      key performance indicators	Styrene & polystyrene1	SBR	Reforming & others
      Fiscal year
      Volume sold 2025 (thousand ton)	84	41	335	460
      Volume sold 2024 (thousand ton)	88	45	336	469
      Variation 2025 vs. 2024	-5%	-8%	-0%	-2%
      Average price 2025 (US$/ton)	1,486	1,615	752	963
      Average price 2024 (US$/ton)	1,744	1,843	832	1,100
      Variation 2025 vs. 2024	-15%	-12%	-10%	-12%
      Fourth quarter
      Volume sold Q4 25 (thousand ton)	22	11	97	129
      Volume sold Q4 24 (thousand ton)	24	12	85	121
      Variation Q4 25 vs. Q4 24	-9%	-7%	+14%	+7%
      Average price Q4 25 (US$/ton)	1,406	1,433	708	886
      Average price Q4 24 (US$/ton)	1,584	1,851	743	1,017
      Variation Q4 25 vs. Q4 24	-11%	-23%	-5%	-13%
      Note: 1 Includes Propylene.

      Holding, transport and others segment, consolidated

      Fiscal year

      Fourth quarter

   3. ‌Analysis of the holding, transport and others segment

      Figures in US$ million	2025	2024	∆%	2025	2024	∆%
      Sales revenue	24	65	-63%	6	36	-83%
      Cost of sales	-	(17)	-100%	-	(12)	-100%
      Gross profit	24	48	- 50%	6	24	- 75%
      Selling expenses	(2)	-	NA	(1)	-	NA
      Administrative expenses	(61)	(98)	-38%	(26)	(60)	-57%
      Other operating income	9	12	-25%	1	8	-88%
      Other operating expenses	(29)	(39)	-26%	-	(5)	-100%
      Income from the sale of associates	-	34	-100%	-	27	-100%
      Results for participation in joint businesses	127	167	-24%	33	38	-13%
      Operating income	68	124	- 45%	13	32	- 59%
      Finance income	-	1	-100%	-	1	-100%
      Finance costs	(49)	(33)	+48%	(11)	(9)	+22%
      Other financial results	94	32	+194%	17	7	+143%
      Financial results, net	45	-	NA	6	(1)	NA
      Profit before tax	113	124	- 9%	19	31	- 39%
      Income tax	18	(33)	NA	10	(21)	NA
      Net income for the period	131	91	+44%	29	10	+190%
      Adjusted EBITDA	166	179	- 7%	42	67	- 38%
      Increases in PPE	9	7	+23%	1	3	-57%
      Depreciation and amortization	-	-	NA	-	-	NA

      The holding, transport and others segment, excluding equity income from affiliates, posted a loss on operating margin of US$20 million in Q4 25, compared to a US$6 million loss in Q4 24, mainly explained by the deconsolidation of OCP Ecuador, which had contributed oil transportation income from August 30, 2024 until the concession ended on November 29, 2024, and lower fee income. These effects were partially offset by lower executive compensation accrual linked to share price performance.

      Financial results showed a net profit of US$6 million (+US$7 million vs. Q4 24, -68% vs. Q3 25), mainly because of improved equity valuation from Oldelval and higher FX gains resulting from the AR$

      devaluation on the segment's net liability position in expenses associated with tax contingencies.	local	currency, partially	offset by	higher interest
      Reconciliation of adjusted EBITDA from holding, transport and others, in US$ million		Fiscal year 2025	2024	Fourth quarter 2025	2024
      Consolidated operating income		68	124	13	32
      Consolidated depreciations and amortizations		-	-	-	-
      Reporting EBITDA		68	124	13	32
      Deletion of equity income		(127)	(167)	(33)	(38)
      Deletion of gain from commercial interests		-	(0)	-	(0)
      Deletion of contigencies provision		-	16	-	-
      Deletion of deferred executive compensation payment		-	43	-	43
      Deletion of the sale of associates		-	(34)	-	(27)
      Deletion of arbitration costs in OCP		0	-	(8)	-
      Deletion of gain from the end of the concession in OCP		-	(4)	-	(4)
      TGS's EBITDA adjusted by ownership		165	163	50	49
      Transener's EBITDA adjusted by ownership		60	38	19	11
      Adjusted EBITDA from holding and others		166	179	42	67

      The adjusted EBITDA for the segment excludes non-operating, non-recurring, and non-cash items and includes EBITDA adjusted for equity ownership in TGS and Transener. In Q4 25, the US$42 million profit (-38% vs. Q4 24, +15% vs. Q3 25) was mainly due to OCP Ecuador's consolidation in Q4 24, partially offset by improved performance at Transener.

      At TGS, the EBITDA adjusted for our stake was US$50 million in Q4 25, in line with US$49 million in Q4 24, explained by higher contributions from the midstream business due to increased natural gas transportation and conditioning services in Vaca Muerta, along with higher NGL processed volumes, particularly ethane. These effects were partially offset by lower international LPG and gasoline prices, narrower premium spreads, and higher operating charges in the NGL segment related to the March 2025 climate event at Cerri. The EBITDA from the regulated segment remained stable, following an 8% tariff increase in Q4 25, in line with inflation (8%).

      At Transener, the EBITDA adjusted for our stake reached US$19 million in Q4 25, up from US$11 million in Q4 24, supported by a 22% tariff hike that outpaced both inflation and devaluation (5%).

2. ‌Cash and financial borrowings

   Cash1Financial debt Net debt As of December 31, 2025, in US$ million Consolidated Ownership Consolidated Ownership Consolidated Ownership
   	in FS	adjusted	in FS	adjusted	in FS	adjusted
   Power generation	1,091	1,083	471	471	(620)	(612)
   Petrochemicals	-	-	-	-	-	-
   Holding and others	(0)	(0)	-	-	0	0
   Oil and gas	-	-	1,421	1,421	1,421	1,421
   Total under IFRS/Restricted Group	1,091	1,083	1,892	1,892	801	808
   Affiliates at O/S2	366	366	394	394	28	28
   Total with affiliates	1,457	1,449	2,286	2,286	829	836

   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, the affiliates CTBSA, Transener and TGS are excluded from Pampa's consolidated figures.

   1. ‌Debt transactions

      During Q4 25, Pampa issued an international CB Series 26 for US$450 million, maturing on a bullet basis in November 2037, with a 7.75% fixed coupon paid semiannually. The 12-year tenor represents a landmark transaction for the Argentine corporate market, marking the first long-dated issuance in more than a decade and doubling Pampa's average debt life to nearly 8 years.

      Pampa continued actively managing its maturity debt profile by paying US$56 million corresponding to Series 16 CB and US$59 million related to the second principal installment of the 2026 Notes. The Company also early redeemed the remaining US$61 million of the 2026 Notes and US$36 million of Series 20, further reducing short- and medium-term maturities.

      As of December 31, 2025, Pampa's financial debt under IFRS totaled US$1,892 million, 9% lower than at year-end 2024. This decrease is mainly due to the early redemption of the 2027 and 2029 Notes, funded with proceeds from the 2034 issuance. However, net debt increased to US$801 million, driven by higher capital expenditures in Rincón de Aranda, collateral posted under crude oil price hedging, and share buybacks, offset by robust free cash flow from the power and gas businesses. Compared to September 2025, net debt decreased by US$72 million, driven by winter cash collections, softer capex requirements in E&P gas and power generation, and lower hedge-related collateral, partially offset by higher investments at Rincón de Aranda.

      As of December 31, 2025, 96% of total gross debt was issued in the capital markets, with the remaining 4% corresponding to bank financing. The gross debt principal breakdown is shown below:

      Type of debt Currency	Legislation	Amount in million US$	% over total gross debt	Average rate	Average life
      Loans US$	Argentine	77	4%	4.94%	1.1
      US$ MEP	Argentine	84	4%	5.75%	2.8
      US$ CB US$-link	Argentine Argentine	105 82	5% 4%	7.25% 0.00%	2.6 2.0
      US$	Foreign	1,560	82%	7.86%	8.9
      Total		1,907	100%	7.28%	7.7

      Proactive liability management allowed Pampa to strengthen its capital structure, extending the average maturity to 7.7 years. The chart below shows the principal maturity profile, net of repurchases, in US$ million by the end of Q4 25:

      
      
      

      1,091

      700

      410

      450

      211

      32

      104

      -

      84

-

Note: The chart only considers Pampa's consolidated figures under IFRS and excludes affiliates TGS, Transener, and CTBSA. The cash position includes cash and cash equivalents, financial assets at fair value with changing results, and investments at amortized cost.

Regarding our affiliates, CTEB repaid US$9 million in bank debt, while TGS obtained new loans for US$101 million and issued international CB Series 4 for US$500 million, maturing in November 2035 with a 7.75% coupon and an 8% yield.

As of today, Pampa remains in full compliance with all debt covenants.

Coupon

Amount outstanding

Maturity

Security

Company

In US$ million

Pampa

TGS1

CB Series 21 at discount & fixed rate 2031 410 7.95%

CB Series 23 at discount & fixed rate 2034 700 7.875%

CB Series 26 at discount & fixed rate 2037 450 7.750%

CB Series 3 at discount at fixed rate 2031 490 8.5%

CB Series 4 at discount at fixed rate 2035 500 7.75%

Pampa CB Series 25 2028 105 7.25%

Pampa CB Series 13 2027 82 0%

CTEB1CB Series 9 2026 26 0%

Pampa CB Series 22 2028 84 5.75%

Note: 1 Under IFRS, affiliates are not consolidated in Pampa's FS.

1. 1. ‌Credit ratings

      Company Agency

      Rating

      Global Local

      S&P B-, bb- (stand-alone) na

      Pampa	FitchRatings	B-	AAA (long-term)1A1+ (short-term)1
      TGS	S&P FitchRatings	B-, b+ (stand-alone) B-	na na
      Transener	FitchRatings	na	AA (long-term)1
      CTEB	FitchRatings	na	AA+1

      Note: 1 Issued by FIX SCR.

2. ‌Appendix

   Fiscal year 2025

   Fiscal year 2024

   Subsidiary

   1. ‌Analysis of the fiscal year, by subsidiary and segment

      In US$ million	% Pampa	Adjusted EBITDA	Net debt	Net income2	% Pampa	Adjusted EBITDA	Net debt	Net income2
      Oil & gas segment
      Pampa Energía	100.0%	375	1,422	(55)	100.0%	346	987	(5)
      Subtotal oil & gas		375	1,422	(55)		346	987	(5)
      Power generation segment
      Diamante	61.0%	7	(0)	3	61.0%	3	(0)	1
      Los Nihuiles	52.0%	1	(0)	(0)	52.0%	(0)	(0)	(0)
      VAR	100.0%	17	(0)	6	100.0%	22	(0)	15
      CTBSA		105	139	25		107	33	(41)
      Non-controlling stake adjustment		(53)	(69)	(12)		(53)	(16)	21
      Subtotal CTBSA adjusted by ownership	50.0%	53	69	12	50.0%	53	16	(21)
      Pampa stand-alone, other companies, & adj.1		394	(620)	276		312	(590)	465
      Subtotal power generation		472	(551)	297		390	(573)	461
      Petrochemicals segment
      Pampa Energía	100.0%	(5)	-	4	100.0%	21	-	72
      Subtotal petrochemicals		(5)	-	4		21	-	72
      Holding, transport & others segment
      Transener		228	(84)	134		143	(97)	68
      Non-controlling stake adjustment		(168)	62	(98)		(105)	72	(50)
      Subtotal Transener adjusted by ownership	26.3%	60	(22)	35	26.3%	38	(26)	18
      TGS		622	(71)	289		630	(210)	359
      Non-controlling stake adjustment		(457)	52	(213)		(467)	155	(266)
      Subtotal TGS adjusted by ownership	26.9%	165	(19)	76	25.9%	163	(54)	93
      Pampa stand-alone, other companies, & adj.1		(59)	0	19		(21)	13	(20)
      Subtotal holding & others		166	(41)	131		179	(67)	91
      Deletions		-	(28)	-		-	63	-
      Total consolidated		1,009	801	377		937	410	619
      At our share ownership		1,005	836	377		935	353	619

      Note: 1 The deletion corresponds to other companies or inter-companies. 2 Attributable to the Company's shareholders.

      Q4 25

      Q4 24

      Subsidiary

   2. ‌Analysis of the quarter, by subsidiary and segment

      In US$ million	% Pampa	Adjusted EBITDA	Net debt	Net income2	% Pampa	Adjusted EBITDA	Net debt	Net income2
      Oil & gas segment
      Pampa Energía	100.0%	77	1,422	(17)	100.0%	36	987	(76)
      Subtotal oil & gas		77	1,422	(17)		36	987	(76)
      Power generation segment
      Diamante	61.0%	1	(0)	41	61.0%	1	(0)	1
      Los Nihuiles	52.0%	3	(0)	(0)	52.0%	1	(0)	1
      VAR	100.0%	6	(0)	44	100.0%	7	(0)	6
      CTBSA		29	139	14		25	33	15
      Non-controlling stake adjustment		(15)	(69)	(7)		(13)	(16)	(8)
      Subtotal CTBSA adjusted by ownership	50.0%	15	69	7	50.0%	13	16	8
      Pampa stand-alone, other companies, & adj.1		86	(620)	80		64	(590)	118
      Subtotal power generation		111	(551)	172		86	(573)	133
      Petrochemicals segment
      Pampa Energía	100.0%	1	-	(23)	100.0%	(7)	-	39
      Subtotal petrochemicals		1	-	(23)		(7)	-	39
      Holding, transport & others segment
      Transener		74	(84)	41		43	(97)	21
      Non-controlling stake adjustment		(54)	62	(30)		(32)	72	(16)
      Subtotal Transener adjusted by ownership	26.3%	19	(22)	11	26.3%	11	(26)	6
      TGS		185	(71)	90		194	(210)	129
      Non-controlling stake adjustment		(135)	52	(66)		(144)	156	(96)
      Subtotal TGS adjusted by ownership	26.9%	50	(19)	24	25.5%	49	(53)	33
      Pampa stand-alone, other companies, & adj.1		(28)	0	(6)		6	12	(29)
      Subtotal holding & others		42	(41)	29		67	(67)	10
      Deletions		-	(28)	-		-	63	-
      Total consolidated		230	801	161		182	410	106
      At our share ownership		228	836	161		181	353	106

      Note: 1 The deletion corresponds to other companies or inter-companies. 2 Attributable to the Company's shareholders.

   3. ‌Consolidated balance sheet

      In US$ million	As of 12.31.2025	As of 12.31.2024
      ASSETS
      Property, plant and equipment	3,303	2,607
      Intangible assets	89	95
      Right-of-use assets	36	11
      Deferred tax asset	43	157
      Investments in associates and joint ventures	1,059	993
      Financial assets at fair value through profit and loss	33	27
      Trade and other receivables	43	75
      Total non-current assets	4,606	3,965
      Inventories	231	223
      Financial assets at amortized cost	-	80
      Financial assets at fair value through profit and loss	366	850
      Derivative financial instruments	52	1
      Trade and other receivables	614	488
      Cash and cash equivalents	725	738
      Total current assets	1,988	2,380
      Total assets	6,594	6,345
      EQUITY
      Share capital	36	36
      Share capital adjustment	191	191
      Share premium	516	516
      Treasury shares adjustment	1	1
      Treasury shares cost	(54)	(7)
      Legal reserve	44	44
      Voluntary reserve	2,399	1,657
      Other reserves	(12)	(13)
      Other comprehensive income	124	119
      Retained earnings	351	742
      Equity attributable to owners of the company	3,596	3,286
      Non-controlling interest	9	9
      Total equity	3,605	3,295
      LIABILITIES
      Provisions	100	137
      Income tax and minimum notional income tax provision	26	75
      Tax liabilities	212	-
      Deferred tax liability	56	49
      Defined benefit plans	26	30
      Borrowings	1,844	1,373
      Trade and other payables	86	84
      Total non-current liabilities	2,350	1,748
      Provisions	13	10
      Income tax liability	83	257
      Tax liabilities	56	30
      Defined benefit plans	6	7
      Salaries and social security payable	36	39
      Borrowings	48	706
      Trade and other payables	397	253
      Total current liabilities	639	1,302
      Total liabilities	2,989	3,050
      Total liabilities and equity	6,594	6,345

   4. ‌Consolidated income statement

      Fiscal year Fourth quarter In US$ million
      	2025	2024	2025	2024
      Sales revenue	1,998	1,876	507	435
      Domestic sales	1,618	1,575	411	368
      Foreign market sales	380	301	96	67
      Cost of sales	(1,369)	(1,279)	(369)	(349)
      Gross profit	629	597	138	86
      Selling expenses	(98)	(74)	(29)	(17)
      Administrative expenses	(192)	(239)	(61)	(100)
      Exploration expenses	-	(21)	-	(21)
      Other operating income	100	175	15	59
      Other operating expenses	(72)	(88)	(10)	(16)
      Impairment of financial assets	(21)	(56)	(16)	-
      Recovery of impairment (Impairment) of PPE, int. assets and inventories	15	(34)	23	(15)
      Results for part. in joint businesses & associates	142	146	41	45
      Income from the sale of associates	-	34	-	27
      Operating income	503	440	101	48
      Financial income	45	32	3	28
      Financial costs	(196)	(185)	(45)	(48)
      Other financial results	230	211	93	97
      Financial results, net	79	58	51	77
      Profit before tax	582	498	152	125
      Income tax	(204)	121	10	(19)
      Net income for the period	378	619	162	106
      Attributable to the owners of the Company	377	619	161	106
      Attributable to the non- controlling interest	1	-	1	-
      Net income per share to shareholders	0.3	0.5	0.1	0.1
      Net income per ADR to shareholders	6.9	11.4	3.0	1.9
      Average outstanding common shares 1	1,360	1,360	1,360	1,360
      Outstanding shares by the end of period 1	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 December 31, 2024 and 2025. Repurchased stock can only be canceled if it is ordinary shares.

   5. ‌Consolidated cash flow statement

      In US$ million	Fiscal year		Fourth quarter
      	2025	2024	2025	2024
      OPERATING ACTIVITIES
      Profit of the period	378	619	162	106
      Adjustments to reconcile net profit to cash flows from operating activities	418	152	11	12
      Changes in operating assets and liabilities	(18)	(336)	115	31
      (Increase) decrease in trade receivables and other receivables	(100)	(411)	119	47
      (Increase) decrease in inventories	(13)	(20)	21	13
      Increase in trade and other payables	69	75	(25)	(5)
      Increase in salaries and social security payables	10	25	8	10
      Defined benefit plans payments	(3)	(3)	(1)	(1)
      Increase (decrease) in tax liabilities	22	17	(3)	(17)
      Decrease in provisions	(10)	(19)	(3)	(16)
      Income tax payment	(8)	-	(8)	-
      Collection for derivative financial instruments, net	15	-	7	-
      Net cash generated by (used in) operating activities	778	435	288	149
      INVESTING ACTIVITIES
      Payment for property, plant and equipment acquisitions	(993)	(447)	(242)	(97)
      Collection for sales (Payment for purchases) of public securities and shares, net	592	(5)	216	21
      Recovery (Suscription) of mutual funds, net	3	(10)	(8)	(9)
      Capital integration in companies	(44)	-	(3)	-
      Payment for companies' acquisitions	(1)	(48)	(1)	-
      Collection for equity interests in companies sales	1	39	-	21
      Collection for joint ventures' share repurchase	-	37	-	-
      Collections for intangible assets sales	9	-	-	-
      Dividends collection	25	9	-	1
      Collection for equity interests in areas sales	7	9	5	9
      Cash addition from purchase of subsidiary	-	71	-	-
      Collection of loans, net	-	1	-	1
      Net cash generated by (used in) investing activities	(401)	(344)	(33)	(53)
      FINANCING ACTIVITIES
      Proceeds from borrowings	986	1,174	432	464
      Payment of borrowings	(306)	(236)	(178)	(142)
      Payment of borrowings interests	(161)	(145)	(39)	(27)
      Repurchase and redemption of corporate bonds	(837)	(313)	(111)	16
      Payment for treasury shares acquisition	(47)	-	(31)	-
      Payment of dividends	(1)	-	(1)	-
      Payment of leases	(24)	(4)	(13)	(1)
      Net cash (used in) generated by financing activities	(390)	476	59	310
      (Decrease) Increase in cash and cash equivalents	(13)	567	314	406
      Cash and cash equivalents at the beginning of the period	738	171	411	332
      (Decrease) Increase in cash and cash equivalents	(13)	567	314	406
      Cash and cash equivalents at the end of the period	725	738	725	738

      
      
      

      ‌4.6	Power generation's main operational KPIs by plant
      Power generation's key performance indicators	PEPE2	PEPE3	Wind PEPE4	PEA	PEPE6	Hydroelectric HINISA HIDISA HPPL			Subtotal hydro +wind	CTLL	CTG	CTP	CPB	Thermal CTPP CTIW		CTGEBA	Eco-Energía	CTEB1	Subtotal	Total
      Installed capacity (MW)	53	53	81	100	140	265	388	285	1,365	780	361	30	620	100	100	1,254	14	848	4,107	5,472
      Contracted capacity (MW)	53	53	81	100	140	41	-	-	469	224	85	-	-	100	100	497	14	279	1,299	1,768
      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%	2.8%	0.03%	1.9%	9.3%	12%
      Fiscal year
      Net generation 2025 (GWh)	206	241	361	322	583	283	520	558	3,074	4,326	261	53	514	139	134	8,144	54	4,325	17,950	21,024
      Market share	0.1%	0.2%	0.3%	0.2%	0.4%	0.2%	0.4%	0.4%	2.2%	3.1%	0.2%	0.0%	0.4%	0.1%	0.1%	5.8%	0.0%	3.1%	12.7%	14.8%
      Sales 2025 (GWh)	215	241	361	322	583	283	520	558	3,083	4,244	448	53	514	139	134	8,566	123	4,321	18,542	21,625
      Net generation 2024 (GWh)	188	202	341	343	197	857	616	890	3,633	4,754	303	59	262	192	145	7,584	70	4,741	18,111	21,743
      Variation 2025 vs. 2024	+10%	+20%	+6%	-6%	na	-67%	-16%	-37%	-15%	-9%	-14%	-9%	+96%	-27%	-8%	+7%	-23%	-9%	-1%	-3%
      Sales 2024 (GWh)	201	202	341	343	195	857	616	890	3,643	4,705	625	59	262	192	145	8,043	150	4,733	18,914	22,557
      Avg. price 2025 (US$/MWh)	89	63	63	79	63	21	28	20	49	32	88	62	92	na	na	39	39	36	42	43
      Avg. price 2024 (US$/MWh)	81	64	64	82	64	13	21	13	35	20	54	30	124	na	na	38	36	30	36	36
      Avg. gross margin 2025 (US$/MWh)	48	54	54	56	55	3	17	7	35	18	38	23	46	na	na	20	14	26	24	26
      Avg. gross margin 2024 (US$/MWh)	49	57	57	64	59	5	10	5	24	17	21	3	24	na	142	19	10	24	22	23
      Fourth quarter
      Net generation Q4 25 (GWh)	57	64	94	96	159	88	154	92	804	1,078	54	22	75	25	35	1,644	15	1,195	4,143	4,947
      Market share	0.2%	0.2%	0.3%	0.3%	0.5%	0.3%	0.5%	0.3%	2.4%	3.2%	0.2%	0.1%	0.2%	0.1%	0.1%	4.8%	0.0%	3.5%	12.1%	14.5%
      Sales Q4 25 (GWh)	56	63	94	96	159	88	154	92	803	1,006	70	22	75	25	35	1,716	32	1,185	4,165	4,968
      Net generation Q4 24 (GWh)	48	57	88	112	125	288	203	231	1,153	975	84	15	22	67	42	1,260	16	1,162	3,644	4,797
      Variation Q4 25 vs. Q4 24	+17%	+11%	+8%	-14%	+27%	-69%	-24%	-60%	-30%	+11%	-36%	+46%	na	-62%	-18%	+30%	-6%	+3%	+14%	+3%
      Sales Q4 24 (GWh)	54	57	88	112	125	288	203	231	1,159	973	152	15	22	67	42	1,399	35	1,154	3,859	5,018
      Avg. price Q4 25 (US$/MWh)	75	63	63	80	63	29	22	25	50	40	112	56	na	na	na	49	36	43	52	51
      Avg. price Q4 24 (US$/MWh)	83	63	63	82	63	13	20	15	36	21	62	36	na	135	na	48	31	30	41	40
      Avg. gross margin Q4 25 (US$/MWh)	44	55	55	59	55	15	13	6	37	19	39	13	76	na	136	18	13	26	25	27
      Avg. gross margin Q4 24 (US$/MWh)	32	37	37	68	58	5	10	7	23	15	23	9	74	115	117	20	8	23	23	23
      Note: Gross margin before amortization and depreciation. 1 Co-operated by Pampa (50% equity stake).

      1. ‌Production in the main oil and gas blocks

         		Fiscal year			Fourth quarter
         In kboe/day at ownership
         	2025	2024	Variation	2025	2024	Variation
         Gas
         El Mangrullo	38.2	43.9	-13%	29.3	30.9	-5%
         Sierra Chata	24.5	18.5	+32%	23.7	17.1	+39%
         Río Neuquén	7.7	9.0	-14%	6.6	7.6	-13%
         Rincón del Mangrullo1	1.0	1.2	-21%	1.0	1.1	-16%
         Others	1.4	0.8	+78%	2.6	0.9	+203%
         Total gas at working interest	72.8	73.4	- 1%	63.2	57.6	+10%
         Oil
         Rincón de Aranda	9.5	0.9	na	17.1	1.0	na
         El Tordillo2	1.1	1.6	-30%	-	1.5	-100%
         Associated oil3	1.0	1.2	-16%	0.9	1.0	-12%
         Los Blancos	0.1	0.2	-70%	-	0.1	-100%
         Gobernador Ayala4	-	0.9	-100%	-	0.4	-100%
         Total oil at working interest	11.7	4.8	+145%	18.0	4.0	+355%
         Total	84.4	78.2	+8%	81.2	61.6	+32%

         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 La Tapera - Puesto Quiroga block. 3 From gas fields. 4 In October 2024, Pampa transferred its 22.51% stake in the concession to Pluspetrol.

      2. ‌Proven reserves (P1), by block and hydrocarbon

      In million boe	Oil	Natural gas	Total	Variation vs. 2024
      Sierra Chata	0.2	95.9	96.1	+41%
      El Mangrullo	0.0	85.2	85.3	-5%
      Rincón de Aranda	52.2	3.9	56.1	+352%
      Río Neuquén	3.7	50.9	54.6	-1%
      Aguaragüe	0.2	1.7	1.9	-5%
      Rincón del Mangrullo	0.0	1.2	1.2	-13%
      Los Blancos	0.7	-	0.7	-2%
      El Tordillo	-	-	-	-100%
      Total as of December 31, 2025	57.0	238.9	295.8	+28%

3. ‌Glossary of terms

2027 Notes: Corporate Bonds maturing in 2027 2029 Notes: Corporate Bonds maturing in 2029 2034 Notes: Corporate Bonds maturing in 2034 ADR/ADS: American Depositary Receipt

AR$: Argentine pesos

B2B: Business to business

Bases Law: Law No. 27,742 enacted on July 8, 2024

Bbl: Barrel

Boe: Barrels of oil equivalent

BTU/MBTU: British Thermal Units/million British Thermal Units

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

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 Regulatory Entity

ENARSA: Energía Argentina S.A.

ENRE: Ente Nacional Regulador de la Electricidad or National Electricity Regulatory Entity

FRA: Adjusted Rent Factor FS: Financial Statements FX: Nominal exchange rate

GPM, former GPNK: Francisco Pascasio Moreno Gas Pipeline, formerly President 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 oil equivalent per day

m3: Cubic meter

MAT: Term power market

mboe: Million barrels of oil equivalent 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, 2020-2024 Supply and Demand Scheme (DNU No. 892/20, 730/22 and supplementary provisions)

PPA: Power purchase agreement PPE: Property, plant and equipment Q3 25: Third quarter of 2025

Q4 25/Q4 24: Fourth quarter of 2025/Fourth quarter of 2024

Res.: Resolution/Resolutions

RIGI: Régimen de Incentivo para Grandes Inversiones or Incentives Regime for Large Investments

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 Distribución Troncal de la Provincia de Buenos Aires Transba S.A.

Transener: Compañía de Transporte de Energía Eléctrica en Alta Tensión Transener S.A.

US$: US Dollar

US$-link: A security in which the underlying is linked to a US$ wholesale exchange rate

US$-MEP: A security in which the settlement uses US$ in the domestic market

WEM: Wholesale electricity market

Earnings release Q4 25 ●