Buenos Aires, May 12, 2025

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.

On May 2, 2025, the shareholders of SESA agreed to move forward with the FLNG Project by executing the final investment decision (FID) for a 20-year charter of the Hilli floating liquefaction vessel, with a nameplate capacity of 2.45 MTPA, as announced on November 29, 2024.

In addition, a second vessel provided by Golar LNG, the MKII, was incorporated, with a nameplate capacity of 3.5 MTPA and under a 20-year charter. Both vessels will be located in the San Matías Gulf, province of Río Negro, and will export up to 6 MTPA of LNG. The Hilli is expected to begin operations in late 2027 or early 2028, with the MKII following by the end of 2028.

SESA, the company established to develop this project, is owned by Pampa (20%), PAE (30%), YPF S.A. through its subsidiary SUR (25%), Wintershall (15%), and Golar Sub-Holding (10%).

To supply the vessels, SESA signed 20-year GSAs with Pampa, PAE, SUR, and Wintershall. Said vessels will require to process 27 mcmpd of natural gas, with Pampa contributing up to 6 mcmpd, representing an increase of almost 50% from the current average production. A dedicated gas pipeline is also planned to be built between the province of Neuquén and the San Matías Gulf to ensure the year-round operation of both vessels.

The MECON approved the FLNG Project under the RIGI (Res. MEC N° 559/25), and the SE recently granted a 30-year unrestricted LNG export permit.

The estimated investment amounts to US$7 billion over 20 years, making this initiative a strategic step to monetize Pampa’s Vaca Muerta reserves, position Argentina in the global LNG market, foster foreign currency inflows, create jobs, and develop local suppliers.

Spot remuneration updates

Note: * These updates exclude hydro power plants under tender process (Alicurá, El Chocón-Arroyito, Cerros Colorados, and Piedra del Águila), which remain the remuneration established in Res. SE No. 113/25 (Executive Order No. 718/24).

Joint tender of HIDISA and HINISA’s concessions

On March 8, 2025, the National Government and the province of Mendoza agreed to jointly tender the HIDISA and HINISA concessions as a single business unit, transferring 51% of the concessionaire’s shares. The Public Enterprise Transformation Agency was appointed to coordinate and carry out the tender process within 60 working days. The current transition period for HINISA’s concession expires on May 31 for both national and provincial contracts. In the case of HIDISA, the national contract expires on May 31 and the provincial contract on October 19.

TGS’s Cerri Complex flood impact

On March 7, 2025, severe flooding halted NGL production and natural gas transportation at TGS’s Cerri Complex, located in the city of Bahía Blanca. Given its strategic nature, the gas transportation service was safely restored on March 24. Works to fully resume NGL production are still underway, and as of today, operations have been partially normalized.

In Q1 25, TGS’s FS recorded a US$13 million loss related to the climate event expenses and impairment of materials and PPE. The final cost has not yet been determined. TGS has filed all relevant documentation with the insurance companies.

Tariff adjustments due to cost variations

TGS five-year tariff review

On April 30, 2025, the ENARGAS published the conditions concluding the RQT process, effective May 2025 until 2030 (Res. No. 256/25). The Res. sets the capital base as of December 31, 2024, the mandatory investments, and a real rate of return on capital post-tax of 7.18%, among other matters. The initial tariff schedule includes a 3.67% increase to April 2025 schedules, applicable from May and spread over 31 monthly and consecutive installments.

This Res. establishes monthly adjustments for cost variations using a 50% PPI and 50% CPI formula, replacing the semi-annual PPI-only adjustment set in the 2017 scheme. This methodology is pending SE’s approval. 

Transener and Transba five-year tariff review

On May 5, 2025, the ENRE published the conditions concluding the RQT process, effective from May 2025 until 2030 (Res. No. 305 and 312/2025). Said Res. establishes the capital base as of December 31, 2024, the mandatory investments, and a real rate of return on capital post-tax of 6.48%, among other matters. The initial tariff schedule includes a 42.89% increase for Transener and 10.30% for Transba, applicable to April 2025 schedules. 20% of the increase will be applied in May 2025, and the remaining 80% will be phased in monthly from June to December 2025.

Additionally, the Res. set a monthly tariff adjustment mechanism for cost variations, combining 33% CPI and 67% PPI.

On March 21, 2025, the MECON approved VMOS’s application to the RIGI (Res. No. 302/25). VMOS aims to build and operate a 437 km oil pipeline between Allen to Punta Colorada, province of Río Negro, with a capacity of up to 700 kbpd. Pampa holds an 11% stake in VMOS and has a contract to transport 50 kbpd, including storage and loading services.

On April 14, 2025, Executive Order No. 269/25 mandates that 100% of export proceeds must be settled through the official exchange market MULC, effectively ending the PIE.

On April 7, 2025, Pampa’s Shareholders Meeting approved the appointments of Gabriel Szpiegel, Daniela Rivarola Meilan, and Nicolás Mindlin* as new Board members, with the latter replacing María Carolina Sigwald*, who resigned on March 5, 2025.

Additionally, the Shareholders’ Meeting approved the tenure renewals of Carolina Zang and Julia Pomares as members, Clarisa Lifsic, Lorena Rappaport, and Diego Martín Salaverri* as alternate members, and the appointments of Flavia Bevilacqua and María Carolina Sigwald* as alternate members of the Board.

Finally, Gabriel Szpiegel and Carolina Zang were designated members of the Audit Committee, and Clarisa Lifsic as an alternate member.

* = non-independent member.

Note: 1 It considers the Employee stock-based compensation plan shares, which amounted to 3.9 million common shares as of March 31, 2024 and 2025.

Note: The amounts of cash and cash equivalents do not consider financial assets at fair value through profit or loss and investments at amortized cost.

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 not consolidated in Pampa.

Debt transactions

As of March 31, 2025, Pampa’s financial debt under IFRS amounted to US$1,691 million, 19% less than the end of 2024. This decrease is mainly explained by the full redemption of the 2027 Notes, funded with proceeds from the international issuance of the 2034 Notes, which amounted to US$353 million of principal plus accrued interests. The gross debt principal breakdown is shown below:

However, the net debt increased to US$577 million, due to the higher seasonal working capital needs and higher capital expenditures destined for Rincón de Aranda’s development and infrastructure.

The issuances of the 2031 and 2034 Notes significantly improved Pampa’s debt maturity profile, extending the average life to 5.0 years. The chart below shows the principal maturity profile, net of repurchases, in US$ million by the end of Q1 25:

Note: The chart only considers Pampa consolidated under IFRS. It does not include affiliates TGS, Transener, and CTBSA.

In addition to the 2027 Notes, Pampa also redeemed CB Series 19 for AR$17,131 million. After quarter-end, Pampa paid bank borrowings for US$40 million and redeemed the outstanding CB Series 18 for US$72 million.

Regarding our affiliates, in Q1 25, CTEB obtained net bank borrowings for US$78 million, paid AR$6 billion in short-term bank calls, and repurchased CB Series 6 for US$30 million. After the quarter-end, CTEB borrowed US$20 million from banks and early redeemed the outstanding CB Series 6 for an amount of US$84 million.

As of today, Pampa continues to comply with all debt covenants.

Summary of debt securities

Notes: 1 Under IFRS, affiliates are not consolidated in Pampa’s FS. 2 CTEB’s Series 6 CB was redeemed on April 30, 2025. 3 Pampa’s CB Series 18 was redeemed on May 8, 2025.

Credit ratings

Note: 1 Local rating issued by FIX SCR.

Note: Net income attributable to the Company’s shareholders.

The slight decline in Q1 25 sales from the oil and gas segment was mainly explained by lower gas sales to Chile and industries and, to a lesser extent, a drop in crude oil volumes, partially offset by higher deliveries under Plan Gas.

Regarding operating performance, total production averaged 72.7 kboepd in Q1 25
(flat vs. Q1 24, +18% vs. Q4 24), mainly explained by lower industrial gas demand due to floods in Cerri, which briefly disrupted gas transportation in March, in addition to the divestment of the Gobernador Ayala block in October 2024 and a slight decline in conventional crude oil production. These effects were partially offset by increased Plan Gas deliveries to CAMMESA, driven by thermal power demand and, to a lesser extent, by higher shale oil production from Rincón de Aranda, where the RDA-2001 well came online in March 2024. The quarter-on-quarter recovery was driven by seasonal demand and higher gas deliveries to CAMMESA.

Gas production in Q1 25 reached 11.8 mcmpd, slightly above Q1 24 and +21% vs. Q4 24 due to seasonality. Analyzing the gas output by block, El Mangrullo block represented 55% of total gas production in Q1 25, with 6.5 mcmpd (-13% vs. Q1 24, +23% vs. Q4 24), followed by Sierra Chata with 30% of the production, reaching 3.5 mcmpd (+51% vs. Q1 24, +22% vs. Q4 24). At non-operated blocks, Río Neuquén remained flat at 1.4 mcmpd (-5% vs. Q1 24, +12% Q4 24), while Rincón del Mangrullo continued declining, producing 0.2 mcmpd (-29% vs. Q1 24, -8% vs. Q4 24).

Note: The net production in Argentina. The gas volume is standardized at 9,300 kilocalories (kCal).

Our gas price in Q1 25 averaged US$3.0 per MBTU (-6% vs. Q1 24, +6% vs. Q4 24), primarily explained by the lower export prices to Chile, in line with lower international reference prices, and seasonal oversupply in the industrial segment. These effects were partially offset by higher retail prices, driven by tariff increases.

Regarding our gas deliveries, during Q1 25, 74% was destined for thermal power generation and 8% to distribution companies, both under Plan Gas. 8% supplied the industrial/spot market, 8% was exported, and the remaining 2% was sold to our petchem plants as raw material. Compared to Q1 24, 66% was destined for thermal power units, 9% was supplied to the retail segment, 14% was sold to the industrial/spot market, 8% was exported, and the remaining 3% was sold to our petchem plants.

Oil production reached 3.2 kbpd in Q1 25 (-25% vs. Q1 24, -18% vs. Q4 24), explained by the sale of our non-operated stake at Gobernador Ayala in October 2024 (-1.1 kbpd), and lower volumes at non-operated conventional crude oil blocks El Tordillo (-0.2 kbpd) and Los Blancos (-0.1 kbpd). The rising shale oil production at Rincón de Aranda partially offset these effects (+0.7 kbpd).

Our oil price in Q1 25 slightly decreased to US$68.4 per barrel, mainly explained by lower Brent-linked export prices. The domestic market absorbed 71% of volume, compared to 69% in Q1 24.

The lifting cost4 recorded US$45 million in Q1 25 (+18% vs. Q1 24, -8% vs. Q4 24), explained by higher gas treatment expenses and well testing at Rincón de Aranda, in preparation for the production ramp-up. The lifting cost per boe rose 20% to US$6.9 per boe produced in Q1 25 vs. US$5.8 per boe in Q1 24, explained by Rincón de Aranda. However, the lifting cost was 20% lower vs. Q4 24 due to higher seasonal output and lower maintenance costs in treatment plants.

Other operating costs, excluding depreciation and amortizations, increased in Q1 25, mainly due to higher trading purchases and transportation and labor costs. Compared to Q4 24, higher royalties and hydrocarbon transportation costs were recorded due to higher seasonal production.

Other operating income and expenses dropped 85% year-on-year, explained by a 75% reduction to US$2 million in Plan Gas income, a compensation to the price agreed in said contract and paid by the Government, due to rising tariffs for distribution companies and, therefore, increased retail sales. Improved collections from CAMMESA and ENARSA, both in days and rate, also led to a 63% decline in commercial interest to US$2 million. There were no significant variations compared to Q4 24.

4 It only considers maintenance, treatment, internal transportation and wellhead staff costs. It does not include amortizations and depreciations.

Financial results in Q1 25 recorded net losses of US$29 million, a 3% improvement vs. Q1 24, mainly explained by contingencies recorded in Q1 24, partially offset by higher FX losses, as lower devaluation impacted the net financial liability position in AR$.

Our oil and gas adjusted EBITDA amounted to US$41 million in Q1 25 (-39% vs. Q1 24, +12% vs. Q4 24), mainly explained by lower gas sales to industries and exports, along with higher operating costs, mostly related to the development of Rincón de Aranda. Higher Plan Gas deliveries, in line with the increased thermal power demand, partially offset these effects. Compared to Q4 24, the improved EBITDA is explained by seasonal demand and lower lifting costs, offset by increased trading purchases and transportation costs. The adjusted EBITDA excludes non-recurring and non-cash income and expenses, as well as overdue commercial interests.

Finally, capital expenditures amounted to US$147 million in Q1 25 (+67% vs. Q1 24), with 78% allocated to the development of Rincón de Aranda.

During Q1 25, power generation sales grew 27% year-on-year, mainly driven by higher spot prices in US$ terms. From February 2024, prices in AR$ rose 136%, outpacing inflation (96%) and AR$ depreciation (28%). Additional drivers include the full commissioning of PEPE 6, which added 140 MW of installed capacity between June and November 2024, with energy sold under the MATER market. Increased recognition of fuel, gas and power transportation tariffs was also recorded, in line with higher thermal demand. However, these gains were offset by associated costs.

Improvement in spot prices mainly benefited capacity payments: open cycles/’peakers’ (GT and ST) averaged US$5.4 thousand per MW-month (+54% vs. Q1 24, +7% vs. Q4 24); hydros earned US$2.4 thousand per MW-month (+47% vs Q1 24, similar to Q4 24); and CCGTs invoiced US$5.9 thousand per MW-month (+30% vs. Q1 24, +67% vs. Q4 24), following the programmed overhauls in Q4 24. CCGTs are the only units under the legacy pricing scheme with a partial income in US$ (Res. SE No. 59/23).

The forced outage of HINISA’s units 2 and 3 due to intense floods in January 2025 reduced sales. Compared to Q4 24, the 17% growth in sales corresponds to a higher dispatch in CTGEBA, as the old CCGT had a major life extension overhaul during Q4 24.

The operating performance of Pampa’s operated power generation was similar to Q1 24, outperforming the national grid, which fell 1.3% year-on-year. This is mainly attributed to the commissioning of PEPE 6 (+135 GWh), higher dispatch in CPB due to improved gas supply at GPM (+83 GWh), stronger wind resource in other wind farms (+39 GWh) and improved availability in CTLL (+27 GWh). These effects were partially offset by the forced outage at HINISA mentioned before (-189 GWh) and programmed overhauls in CTEB’s GT02 in March 2025 (-95 GWh).

The total availability of Pampa’s operated units dropped 307 basis points to 93.4% in Q1 25, compared to Q1 24’s 96.5%, mainly explained by HINISA’s outage, offset by the commissioning of PEPE 6. However, the thermal availability rate improved 21 basis points, reaching 95.8% during Q1 25, which was mainly related to CTLL and CTEB’s improvements.

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

Excluding depreciation and amortizations, net operating costs increased by 39% to US$79 million in Q1 25, mainly explained by lower overdue interest from CAMMESA, higher gas and power transport costs and lower capitalization of maintenance works, in addition to increased power purchases to cover contracts. These effects were partially offset by lower insurance and contractor costs, and higher insurance recovery. Compared to Q4 24, operating expenses fell 16%, reflecting increased insurance recovery and lower maintenance and labor costs, partially offset by higher power purchases.

Financial results in Q1 25 reached a net profit of US$25 million, 32% lower vs. Q1 24, due to lesser gains from financial instruments, partially offset by recovery of penalties at PEA and lower financial expenses from reduced AR$-debt.

Adjusted EBITDA from the power generation segment was US$130 million, a 51% increase year-on-year, mainly boosted by higher spot prices in US$ terms, the addition of PEPE 6 and operational improvements, especially in PPAs units (CAMMESA and private). In Q1 24, results had been affected by a US$20 million impairment on CAMMESA’s trade receivables. These gains were partially offset by higher operating expenses. Adjusted EBITDA excludes non-operating, non-recurrent and non-cash items and considers CTEB’s 50% ownership, which posted US$14 million in Q1 25, similar to Q1 24. Quarter-on-quarter, the higher EBITDA is explained by seasonality, PEPE 6 and lower operating expenses.

Finally, excluding CTEB, capital expenditures totaled US$9 million in Q1 25 vs. US$24 million in Q1 24, explained by the completion of PEPE 6 in Q4 24.

The adjusted EBITDA for the petrochemicals segment reported a US$4 million loss in Q1 25, compared to US$11 million gain in Q1 24, mainly due to an overhaul at the Reformer plant in February 2025, which reduced production by 30%, and to a lesser extent, lower of styrene and polystyrene prices and volumes and higher operating expenses. Increased SBR exports partially offset these effects. Adjusted EBITDA excludes a US$17 million gain from the reversal of a customs contingency.

The total volume sold was 84 thousand tons (-24% vs. Q1 24), impacted by the plant maintenance shutdown mentioned before and lower sales across most products, except SBR exports and domestic polystyrene sales. 

In Q1 25, financial results from the petrochemicals segment recorded a profit of US$26 million, compared to a US$1 million loss in Q1 24, mainly explained by contingency recoveries.

Note: 1 Includes Propylene.

The holding and others segment, excluding equity income from affiliates TGS and Transener, posted a loss on operating margin of US$13 million in Q1 25 vs. an improvement compared to the US$24 million loss in Q1 24, mainly explained by lower provisions for contingencies and higher fee income, partially offset by increased contractor costs.

In Q1 25, financial results showed a net profit of US$7 million vs. a US$5 million loss in Q1 24, mainly explained by gains from the slower AR$ devaluation on tax credits and lesser financial expenses from reduced AR$ debt, partially offset by lower interest income.

The adjusted EBITDA from our holding and others segment excludes non-operating, non-recurring and non-cash items and includes the EBITDA adjusted by equity ownership in TGS and Transener. The US$53 million profit in Q1 25, significantly above the US$23 million in Q1 24, was due to higher contributions from TGS and Transener and, to a lesser extent, improved losses from the corporate segment (US$5 million in Q1 25 vs. US$10 million in Q1 24).

In TGS, the EBITDA adjusted by our stake was US$46 million in Q1 25, compared to US$27 million in Q1 24, mainly driven by tariff increases in the regulated gas transportation business, partially offset by higher operating costs and lower NGL sales due to the weather-related disruptions at Cerri Complex.  Operating losses from said event for US$10 million were excluded from EBITDA.

In Transener, the EBITDA adjusted by our stake was US$13 million in Q1 25 vs. US$6 million recorded in Q1 24, mainly due to tariff hikes.

Note: 1 The deletion corresponds to other companies or inter-companies. 2 Net debt includes holding companies. 3 Attributable to the Company’s shareholders.

Note: Gross margin before amortization and depreciation. 1 Co-operated by Pampa (50% equity stake).

Note: Production in Argentina. 1 It does not include shale formation. 2 It includes the La Tapera – Puesto Quiroga block.
3 On October 21, 2024, Pampa transferred its 22.51% stake in the concession at the Gobernador Ayala to Pluspetrol. 4 From gas fields.