The Law conferred legal status to the ‘Hydrocarbons Unconventional Exploitation Concession’ concept created by DNU No. 929/13 for the extraction of liquid and/or gaseous hydrocarbons by unconventional stimulation techniques applied in reservoirs situated in geological formations of schist rock or slate (shale gas or shale oil), tight sandstone (tight sands, tight gas, tight oil), coal bed methane and/or characterized by the presence of low permeability rocks.

Holders of hydrocarbon exploration permits and/or exploitation concessions may request an unconventional exploitation concession to the enforcement authority until December 31, 2028. This application must include the development of a pilot plan for the field’s commercial exploitation, and adjacent unconventional blocks may be unified, provided geological continuity is demonstrated.

Unconventional hydrocarbons exploitation concession (CENCH) in the Province of Neuquén

The Ministry of Energy and Natural Resources of the Province of Neuquén set certain parameters to grant a CENCH (Res. No. 53/20 and 142/21, ratified by Provincial Executive Order No. 2183/21).

Companies are required to submit annual development plans for up to five years, demonstrating their technical and economic feasibility, along with additional parameters related to operations, actual productivity assessments, costs and investment commitment. Once the request is filed, a block extension bond payment is incorporated. Its value will be associated with the resources expected to be recovered in the block, considering the average price over the last 2 years.

The terms for the exploration permits will be established in each call for tenders issued by the enforcement authority according to the exploration’s target: (i) conventional exploration, divided into two 3-year periods, plus an optional extension of up to 5 years (maximum 11 years); (ii) unconventional exploration, divided into two 4-year periods, plus an optional extension of up to 5 years (maximum 13 years); and (iii) onshore and offshore exploration, divided into two 3-year periods, plus an optional extension of one year each.

Upon expiration of the basic term’s first period, the permit holder will decide whether to continue exploring the block or entirely relinquish it to the Government. The originally granted block may be kept provided permit obligations are met. If the exploration permit holder exercises the right of extension upon the basic term’s expiration, the relinquishment will be limited to 50% of the remaining block. In exploitation concessions, terms run as from the date of the granting Res.: (i) conventional exploitation, 25 years; (ii) unconventional exploitation, 35 years; and (iii) onshore and offshore exploitation, 30 years.

Exploitation concessions granted before the Bases Law’s enactment will continue being governed by the established terms until expiration. After that, they may not be awarded without a new tender process. Under the new concessions, the above-mentioned terms remain in place, and the authority may, in its discretion, extend them for up to 10 additional years.

Law No. 17,319, amended by Laws No. 27,007 and 27,742, proposes model tender specifications drawn up by the SE and the provincial authorities establishing the conditions, guarantees and minimum investments to which tenders must conform. It also establishes adjustment mechanisms for royalties that may consider investments made, income earned and operating expenses, among other variables. The evaluation of tenders will consider the project’s total value, and tenderers will compete for royalties, with a base rate of 15% plus a percentage of their choice, which may even be negative.

Levy values per km² or fraction will be paid annually in AR$ and in advance by the permit holder, adjusted in accordance with the average Brent crude oil barrel price. The amount equals 0.50 bbl of oil per km² in the first period and 2 oil barrels per km² in the second period. In extensions, the levy is the equivalent in AR$ to 15 bbl of oil per km².

Royalties are the only production-based income mechanism the granting jurisdictions will receive monthly, and they are set as a percentage during the awarding process. Contracts before to the Bases Law range from 12% to 15%, as agreed with the PEN or Province, and may be reduced to 5% depending on the wells’ productivity, conditions and location.

The Bases Law replaces concessions with transportation concessions, granted and extended for the same term as the originating exploitation concession. After these terms’ expiration, the facilities will be transferred to the Federal or Provincial Government, as applicable, without any charges or encumbrances. Previous concessions will be governed by the terms and conditions under which they were awarded.

Moreover, the Bases Law enables the grantor to issue authorizations to process hydrocarbons and derivatives, and to construct and operate natural gas conditioning, separation and liquefaction plants, as well as the necessary facilities, without being linked to an exploitation concession. Holders of processing projects and/or facilities may request an indefinite-term transportation authorization to and from their facilities. Holders authorized before the Bases Law will not be required to apply for the reconversion of the granted authorizations (DNU No. 1,057/24).

Under the Bases Law, the PEN may authorize the underground storage of gas in depleted natural hydrocarbon reservoirs to any subject who (i) meets technical experience and financial capacity requirements, (ii) has the consent of the holder of the exploration permit and/or exploitation concession where the reservoir is located, and (iii) builds the necessary facilities.

These authorizations will be granted for an indefinite term, and holders of storage authorization may apply for transportation to and from their facilities to the transportation system. Exploitation bonds and similar payments will be made. Likewise, stored natural gas will only pay royalties when first marketed.

The Bases Law establishes that international hydrocarbon trade will be free and unobjectionable by the SE, except during the 30 administrative working days following the exercise of the export right, founded on domestic supply security.

The Bases Law empowers the PEN to draw up, with the provinces’ agreement, harmonized environmental legislation primarily aimed at applying the best international environmental management practices in hydrocarbon exploration, exploitation and/or transportation activities, and at achieving the activity’s development with proper environmental care.

Created in 2020, Plan Gas promoted Argentine natural gas production and managed the impact of gas costs on the Priority Demand tariff through tendering long-term supply agreements (DNU No. 892/20). Initially, the term for onshore production was 4 years, with an additional 4 years for offshore production from January 2021. Later, the term was extended until December 31, 2028, for the volumes awarded under rounds 1 and 3 (DNU No. 730/22).

Agreements were executed between producers (as sellers) and CAMMESA, gas distributors and ENARSA (as purchasers), with a 100% daily DoP and a 75% monthly ToP for CAMMESA and a quarterly ToP for gas distributors and ENARSA. The following seasonal adjustment factors are applied to the awarded price: 0.82 in the summer period (October – April) and 1.25 (May -September). CAMMESA and ENARSA pay the price awarded in the tender. Distributors pay the amount under the current tariff scheme, with the difference compensated by the Federal Government, guaranteed through tax credit certificates.

In December 2020, round 1 was awarded for an annual base volume of 67.4 mcmpd at US$3.5/MBTU as of January 2021 and a winter additional volume of 3.6 mcmpd at US$4.7/MBTU as of May 2021 (SE Res. No. 391/20 and 447/20). In December 2022, rounds 4.1 and 5.1 extended, until December 2028, 48.0 mcmpd in the Neuquina Basin at US$3.592/MBTU and 2.4 mcmpd in the Austral Basin at US$3.479/MBTU (SE Res. No. 860/22).

Round 2 was awarded in March 2021, with an increasing daily DoP and a 75% quarterly ToP for a base volume of 3.3 mcmpd during winter at US$4.7/MBTU from June 2021 (SE Res. No. 169/21).

Round 3 was awarded in November 2021 for an annual base volume of 3 mcmpd at US$3.43/MBTU from May 2022 (SE Res. No. 1091/21). In December 2022, it was extended at US$3.435/MBTU in the Neuquina Basin until December 2028 (SE Res. No. 860/22).

Round 4.2 awarded new volumes until December 2028. Awardees may limit up to 30% of the volume committed with ENARSA for industrial customers and/or CNG, subject to SE’s approval. The tender calls were:

• Annual flat commitment from July 2023: 11 mcmpd at US$3.41/MBTU;
• Annual flat commitment from January 2024: 3 mcmpd at US$2.989/MBTU;
• Peak (winter) commitment from May 2024: 7 mcmpd at US$4.249/MBTU; and
• Peak (winter) commitment from May 2025: 7 mcmpd at US$3.597/MBTU.

Finally, round 5.2 awarded the incremental volumes set monthly in the Austral, Golfo San Jorge and Noroeste Basins for 3.3 mcmpd at US$7.319/MBTU from October 2023 to December 2028. The customers are ENARSA and CAMMESA, with an 80% daily DoP and a 0% monthly ToP (SE Res. No. 799/23).

Historical Pampa awards under Plan Gas.Ar

Pampa’s awards under each round are detailed below:

Note: 1 It covers May through September. 2 1.25 adjustment factor in the winter and 0.82 for the rest of the year. 3 Prices start at US$9.8/MBTU and drop to US$6/MBTU in 2028.

Plan Gas contracts pass-through

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 to 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.

Priority Demand and CEE

In June 2016, CEE criteria were established to guarantee the Priority Demand’s supply in case of operational emergencies (MEyM Res. No. 89/16, as amended). In June 2017, the procedure for dispatch administration in the CEE was approved (ENARGAS Res. No. 4,502/17). If the CEE does not reach an agreement, ENARGAS defines the required supply considering each producer’s available quantities and deducts the amounts previously contracted to meet the Priority Demand, with a progressive allocation until matching each producer/importer’s proportional quota in the Priority Demand.

Natural gas prices within the PIST

As of January 2021, gas volumes for the Priority Demand are contracted under Plan Gas. Gas distributors pay the price stated in the effective tariff scheme, and the Federal Government offsets the difference with Plan Gas’s awarded price. ENARSA pays 100% of the Plan Gas’ awarded price.

Regarding subsidies granted directly to residential users under the social tariff, as of February 1, 2025, ENARGAS established that such compensation will be received directly by natural gas producers and deducted from the invoices issued to distributors (Res. No. 125/25).

Since the end of 2019, power plants’ fuel supply has been centralized in CAMMESA, except for generators with PPA under Energía Plus and SEE Res. No. 287/17 (MDP Res. No. 12/19). CAMMESA launches calls on an interruptible basis to cover its monthly consumption, and most gas has been supplied under Plan Gas since 2021. Generators under Energía Plus and SEE Res. No. 287/17 PPA can assign natural gas operation and transportation to CAMMESA. Pampa opted into this scheme. As of 2021, reference PIST prices were set for production out of Plan Gas at US$2.3/MBTU in the summer (October – April) and US$3.5/MBTU in the winter period (May – September) for the Neuquina Basin (SE Res. No. 354/20). In addition to Plan Gas, CAMMESA launches calls with a maximum price equal to Plan Gas and 30% DoP, although the volume is marginal. Likewise, CAMMESA’s dispatch prioritized compliance with the gas import contracts from Bolivia executed by ENARSA and with the commitments under Plan Gas (Res. SE No. 354/20).

On January 28, 2025, the SE repealed this dispatch regime and, as of March 1, 2025, authorized the recognition of fuel costs based on reference prices and declared and accepted CVP, including freight, natural gas transportation and distribution, taxes, and fees.

With the entry into force of Res. SE No. 400 and 501/25, the natural gas supply scheme for power plants has become more flexible, allowing generators greater direct management. This new framework includes a transitional stage in which CAMMESA may continue to supply fuel under specific circumstances, gradually moving toward a model in which generators assume full responsibility for gas procurement and transportation capacity. CAMMESA will act as the last resort supplier until 2029, when comprehensive fuel management will become the generators’ responsibility.

In addition, CAMMESA will continue to centralize fuel management for PPAs under Res. SE No. 220/07, 21/17, and 287/17. In 2025, Pampa self-supplied natural gas to CTLL and CTGEBA.

In April 2021, a procedure was regulated to authorize natural gas exports on a firm and preferential basis for Plan Gas awardees during the summer period, with the option to extend it to the winter period in case of oversupply at a specific basin, subject to the applicable authority’s prior approval (SE Res. No. 360/21). In November 2022, exports were authorized on a firm basis in winter, prioritizing producers with competitive prices and/or a higher contribution under Plan Gas (DNU No. 730/22). In addition, the SE established amendments, such as (i) export limitations per producer to a maximum of 30% of the authorized volume per basin or 50% of the commitment under Plan Gas, (ii) quotas per basin for firm exports, (iii) the exported volume will be deductible from the Plan Gas summer commitment, and (iv) the minimum price will be the higher between a Brent percentage and the Plan Gas price with the adjustment factor (SE Res. No. 774/22).

On July 8, 2024, the Bases Law provided for free sale unobjectionable by the SE, requiring SE Res. No. 360/21’s readjustment. This regulation is still pending.

The Bases Law establishes a special LNG export regime for entities that produce, process, refine, market, store and/or fractionate hydrocarbons and/or their derivatives, without objection from the SE, within 120 administrative working days from the presentation of the export notification.

LNG export authorizations will be firm sales for up to 30 years from the commissioning of the liquefaction plant or its expansions. The SE will evaluate the long-term availability of gas resources to supply domestic demand at least every five years, or when a new LNG export request warrants it based on its scale, terms or investment amounts (DNU No. 1,057/24). On April 4, 2025, the SE approved the LNG export procedure (Res. No. 145/25).

As of May 2020, export duties are exempted provided the international Brent price is equal to or lower than US$45/bbl, with progressive increases until the reference price reaches 8%, the cap to be recognized when the Brent price equals or exceeds US$60/bbl (DNU No. 488/20). In 2025, the rate remained at 8%.

In October 2023, Pampa adhered to the regime that allowed hydrocarbon exporters to partially settle their exports at the differential blue-chip swap rate, with the remainder settled at the official FX (DNU No. 576/22). However, as of April 14, 2025, the PIE was terminated, establishing that 100% of export proceeds must be settled in the Single and Free Foreign Exchange Market (MULC) (DNU No. 269/25).

TGS’s license to operate the natural gas transportation system will expire in December 2027. On September 8, 2023, TGS requested ENARGAS to initiate the renewal process. The original contract provided for a 10-year extension, but the Bases Law, approved in July 2024, allows a 20-year extension.

On June 13, 2024, ENARGAS issued a favorable technical and legal report, highlighting TGS’s compliance with its obligations and authorizing ENARGAS to hold a non-binding public hearing on October 21, 2024 and to submit his recommendation to the PEN, formalized on July 24, 2025, which provided for the extension of the transportation license for 20 years as from its expiration in December 2027 (DNU No. 495/25).

The GPM, declared of national public interest in February 2022, is a strategic project for Argentina’s gas development (SE Res. No. 67/22). ENARSA was appointed as concession holder for 35 years and is the trustor and beneficiary under the FONDESGAS trust (Fondo de Desarrollo Gasífero Argentino, Argentine Gas Development Fund) with Banco de Inversión y Comercio Exterior S.A. (BICE) acting as trustee (DNU No. 76/22). On June 5, 2023, ENARSA awarded TGS the technical operation of GPM’s first section for 5 years, extendable for up to 12 months, including the two compression plants at Tratayén and Salliqueló, which increased transportation capacity from 11 to 21 million m³ per day in 2024. TGS has also been the technical operator of the Mercedes Cardales Gas Pipeline for a 5-year term.

In June 2024, TGS submitted to the Federal Government a private initiative proposal on the GPM and an investment commitment in the regulated system, aiming to substitute gas oil and LNG imports with gas from Vaca Muerta, guaranteeing domestic supply and FX savings for the country. The private initiative proposal, declared of public interest in December 2024 (DNU No. 1,060/24), envisages the expansion of GPM’s transportation capacity from 21 mcmpd to 35 mcmpd under the RIGI and as provided in the Hydrocarbons Law.

On February 25, 2025, the MECON delegated to the SE and ENARSA the responsibility for conducting the tender process (Res. No. 169/25). On March 28, the SE approved the bidding documents and the guidelines for the commercialization of GPM’s incremental capacity and the final loops of the regulated system operated by TGS. On May 28, ENARSA formally launched the tender. Bids were submitted on July 28, 2025, with TGS as the sole bidder. On October 20, the SE notified the award, and TGS submitted the corresponding guarantees (Res. No. 397/25). Finally, on October 26, TGS requested that the private initiative adhere to the RIGI, which remains pending approval as of today.

The private initiative project contemplates the installation of three new compressing plants and 90,000 HP of additional power, enabling an increase of 14 mcmpd in the GPM’s transportation capacity. The works must be completed before April 30, 2027, and the estimated investment is US$560 million. Additionally, TGS expects to invest approximately US$220 million to expand transportation capacity by 12 mcmpd in the final loops of the regulated system by incorporating an additional 15,000 HP, to be repaid through the regulated tariff.

For the operation and maintenance of the GPM, a contract between ENARSA and TGS is envisaged, with the allocation of reserved capacity as consideration. Under this scheme, TGS will receive from shippers the price offered in the tender, thereby recovering the related investments and operating expenses.

The Household Gas Bottles’ Program, effective since 2015, subsidized the price of LPG gas bottles for low-income users (DNU No. 470/15 and amendments). In August 2021, a temporary economic assistance program was established, equivalent to 20% of the revenue generated from LPG sales destined for Household Gas Bottles’ Program from August 2021 to December 2022 (SE Res. No. 809/21 and its amendments). Under the circumstances, participation in this program required TGS to produce and market LPG at prices significantly below market levels, making it necessary to adopt mechanisms aimed at mitigating its negative impact.

On January 22, 2025, the SE ordered the elimination of subsidies and set the export parity price as the maximum sale price (Res. No. 15/25). On July 3, 2025, further progress was made toward liberalizing the producer sale price, while maintaining the obligation to supply the domestic market (DNU No. 446/25).

On September 22, 2025, TGS signed a new Agreement for the Supply of Propane Gas for Undiluted Propane Gas Distribution Grids. The agreement establishes the compensation calculated as the difference between the sale price and the export parity published monthly by the SE. The Federal Government will pay the compensation through tax credit certificates, which are only applicable to the cancellation of hydrocarbon export duties.

The agreement was in force from January 1 to December 31, 2025, and experienced significant delays in collections. However, on December 26, the SE requested that producers continue supplying under the same terms until a new agreement is executed.

As with hydrocarbon exports, as from May 2020, export duties are exempted as long as the international Brent price is equal to or lower than US$45/bbl, with progressive increases until the reference price reaches 8%, the cap to be recognized when the Brent price equals or exceeds US$60/bbl (DNU No. 488/20). In 2025, the rate remained at 8%.