Stock information		Buenos Aires, November 4, 2025 Basis of presentation Pampa reports its financial information in US$, its functional currency. For local currency equivalents, transactional FX is applied. However, Transener and TGS’s figures are adjusted for inflation as of September 30, 2025, and converted into US$ 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 production in Rincón de Aranda, increased gas exports to Chile, and fuel self-procurement at CTLL, partially offset by lower gas sales 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’s expansion.     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 the strong 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 gas demand. Net income attributable to shareholders was US$23 million, 84% below Q3 24, mainly explained by higher non-cash deferred tax charges, which also impacted results on our affiliates’ equity income, partially offset by improved 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 share buybacks. After the quarter’s closing, net debt decreased to US$790 million, resulting in a 1.1x ratio.
	Buenos Aires Stock Exchange Ticker: PAMP
	New York Stock Exchange Ticker: PAM 1 ADS = 25 common shares
Share capital net of repurchases 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 the videoconference Date and time: Wednesday, November 5 10 AM Eastern Standard Time 12 PM Buenos Aires Time Access link: bit.ly/Pampa3Q2025VC For further information about Pampa Email investor@pampa.com Website for investors ri.pampa.com/en Argentina’s Securities and Exchange Commission www.argentina.gob.ar/cnv US Securities and Exchange Commission sec.gov

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.

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 competition among generators, encouraging direct contracting between demand and generators, and promoting a more decentralized fuel-supply scheme. Effective November 1, 2025, the new framework introduces changes to the spot market and splits the forward market into two segments: energy and capacity. It also 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% of their 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 each generator: i) new generation FRA = 1, retaining the full margin; ii) legacy generation with own fuel procurement 15% from 2025, 25% from 2027, and 35% from 2028; iii) legacy generation with gas supplied by CAMMESA 12% from 2025, 15% from 2027, and 17.5% from 2028; and iv) legacy generation 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. Units commissioned before January 1, 2025, maintain a FRA equivalent to thermal generation, with minimum RMA floors of i) US$22/MWh for hydroelectric plants; 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 and applying 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 using alternative 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 payments at 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 full responsibility 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 Plan and/or LNG imports, updated biweekly.

This new framework upholds existing PPAs, whose energy output remains allocated to meet distribution companies’ seasonal demand until their expiration. 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 those units, Pampa operates three strategically located CCGTs: CTLL in Vaca Muerta; CTGEBA at the central system node; and CTEB, which uses natural gas and 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.

Last price updates for the legacy or spot scheme

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 contract and additional conditions, including updating guarantees, waiving any claims against the State related to changes in the remuneration scheme, and paying 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 not accept the proposed terms, it will be required to continue operating the asset for 90 calendar days, allowing the National Government to implement the necessary 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 its participation in the process.

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 TGS in June 2024. The project involves installing three new compressor plants and adding 90,000 HP of capacity, increasing GPM’s transportation capacity from 21 mcmpd to 35 mcmpd. The expansion is expected to require an estimated investment of US$560 million, with works scheduled for completion before 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 trunk pipeline 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

On October 1, 2025, Pampa transferred its 35.67% stake in the El Tordillo, La Tapera and Puesto Quiroga concessions for US$2 million, subject to a clean exit condition. With this transaction, Pampa no longer holds assets in the San Jorge Gulf basin.

On September 8, 2025, Pampa’s Board of Directors approved the 14th share repurchase program, for up to US$100 million or 10% of share capital, 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 have been repurchased at an average of US$58.8/ADR, representing 1.5% of Pampa’s issued share capital.

On November 30, 2024, OCP Ecuador transferred its ownership in the pipeline to the Ecuadorian State. As part of the transaction, OCP Ecuador had 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, along with the corresponding monetary reimbursement to OCP Ecuador. However, Citibank Ecuador, the issuing bank, declined to release the guarantees on that date, citing non-compliance with certain formal requirements. This led to the initiation of arbitration proceedings seeking the release of the guarantees and compensation for damages.

Subsequently, on October 28, 2025, the Ecuadorian State formally notified Citibank Ecuador of the expiration of the guarantees and instructed their 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.

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

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 at Rincón de Aranda, increased gas to Chile, fuel self-procurement at CTLL, and the industrial segment. These effects were partially offset by lower sales in September, explained by weaker retail demand due to milder weather and the expiration of Plan Gas winter peak commitments, as well as lower crude oil 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), mainly explained 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 seasonal gas 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 Mangrullo accounted 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.

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 for CTLL 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% to distribution companies (vs. 36% in Q3 24), both under Plan Gas GSA. The year-on-year decrease reflects the end of Plan Gas winter commitments in September 2024, lower retail demand due to milder September weather, and fuel self-procurement in CTLL, which itself accounted for 6% of Q3 25 deliveries. 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 to increased 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 in October 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. Q3 24).

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), mainly reflecting lower Brent prices. Without Rincón de Aranda’s partial price hedge, in place since April 2025, the average oil price would have been US$60.3 per barrel. Exports accounted for 47% of total sales in Q3 25, similar to Q3 24, although export volumes quadrupled year-on-year.

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 TPF leasing 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 in Q3 25 vs. US$6.0 per boe in Q3 24, mainly explained by higher operating expenses mentioned before, though partially offset by increased production at Rincón 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 to higher 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 partially offset 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 operating net income rose significantly, explained by higher Plan Gas compensation from seasonality and slightly higher days sales outstanding, partially offset by higher environmental provisions.

Financial results in Q3 25 posted net losses of US$47 million (+96% vs. Q3 24, +81% vs. Q2 25), mainly explained by higher FX losses from a steeper AR$ devaluation impacting the segment’s net monetary asset position in AR$, as well as lesser gains from holding financial securities, partially offset by gains from the crude oil price hedge.

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 accelerated shale 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-quarter improvement in EBITDA. The adjusted EBITDA excludes non-recurring and non-cash income and expenses, as well as overdue commercial interests and equity income from affiliates, and includes a US$10 million adjustment to the rights-of-use amortization, reflecting the reclassification of the TPF rental at 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 of Rincón 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-use amortization in the cost of sales. Lifting cost does not include amortizations and depreciations.

In Q3 25, power generation sales increased 12% year-on-year, mainly driven by higher revenue from CTLL’s fuel self-procurement during the winter peak and, to a lesser extent, by PEPE 6’s contribution, higher spot capacity prices and greater PPA sales to industrial clients. These effects were partially offset by lower thermal dispatch. Compared to Q2 25, the sales growth reflects seasonal increases in generation and the completion of scheduled 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. Q3 24, -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 from CAMMESA amid weak electricity consumption and higher penetration of renewable and nuclear power generation, as well as scheduled maintenance outages. This follows a 2% contraction in national power demand, linked to softer economic activity and milder weather. Analyzing by plant, lower generation 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 in
Q2 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 by programmed maintenance at CTGEBA’s GT04 and CTLL’s GT05, and forced outages at CTLL’s GT04 and HINISA, the latter ongoing since January. These variations 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.

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 gas purchases 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 financial transaction 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 financial securities, partially offset by higher interest income.

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 reduced dispatch. Adjusted EBITDA excludes non-operating, non-recurrent and non-cash items and considers CTEB’s 50% ownership, which posted US$15 million in Q3 25 (flat vs. Q3 24, +74% vs. Q2 25). The additional spot capacity remuneration and higher industrial sales explain the quarter-on-quarter improvement in EBITDA.

Finally, excluding CTEB, capital expenditures totaled US$18 million in Q3 25, down from US$24 million in Q3 24, mainly allocated to maintenance.

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 outage of the polystyrene plant and a non-recurrent US$3 million gain recorded in Q3 24 from exports settlements at a differential FX. These effects were partially offset by higher exports of reforming products and lower raw material costs. The drop in EBITDA compared to Q2 25 is mainly due to lower reforming 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, partially offset 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.

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 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 the absence of OCP Ecuador, which had contributed US$8 million of operating income during its short consolidation in Q3 24. These effects were partially offset 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.

The adjusted EBITDA from our holding and others segment excludes non-operating, non-recurring, and non-cash items and includes EBITDA adjusted 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 higher corporate 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$40 million in Q3 24, explained by lower regulated margins, as the 5% tariff increase during Q3 25 lagged behind 6% inflation and 15% AR$ devaluation, partially offset by higher exports of NGL and ethane 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 hike that outpaced both inflation (6%) and devaluation (15%).

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.

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 of 7.25%. 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 is mainly due to the early redemption of the 2027 and 2029 Notes, funded with proceeds from the issuance of the 2034 Notes. However, net debt increased to US$874 million, driven by higher capital expenditures in Rincón de Aranda, share buybacks and increased collateral requirements related to the 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$84 million. 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 to bank financing. The gross debt principal breakdown is shown below:

Through proactive liability management, Pampa continued to strengthen its debt profile, extending the average maturity to 5.6 years. The chart below shows the principal maturity profile, net of repurchases, in US$ million by the end of Q3 25:

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 cancelled bank borrowings for US$15 million, while TGS extended debt maturities by US$26 million and obtained new loans for US$19 million.

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

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

Note: 1 Issued by FIX SCR.

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

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.

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 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.