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 operation, 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.

In new concessions, the above-mentioned terms are maintained, and the authority may justifiably extend them for up to 10 more 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 conditions, guarantees and minimum investments to which tenders must conform. It also establishes adjustment mechanisms for royalties, which may consider investments made, income obtained 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 15% value 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 as per the average Brent crude oil barrel price. The amount equals 0.50 bbl of oil per km² in the first 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 on a monthly basis and are set as a percentage in the awarding process. Contracts prior 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 construct and operate natural gas conditioning, separation and liquefaction plants and 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 the 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. For LNG, the Undersecretariat of Liquid Fuels informed producers that until regulations are readjusted, the current authorization procedure would remain in effect (Note No. 135497092).

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 tasks and achieving the activity’s development with proper environmental care.

Created in 2020, Plan Gas promotes Argentine natural gas production and manages the gas cost impact on the Priority Demand’s 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 70 million m³/day base volume awarded under rounds 1 and 3 (DNU No. 730/22).

Agreements are 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 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), 1.25 (May -September) for the base volume and 1.30 for the additional volume in the winter period. CAMMESA and ENARSA pay the price awarded in the call for tenders. Distributors pay the amount according to the current tariff scheme, with the difference being compensated by the Federal Government, guaranteed by tax credit certificates, without prejudice to other applicable mechanisms.

In December 2020, round 1 was awarded for an annual base volume of 67.4 million m³/day at US$3.5/MBTU as of January 2021 and a winter additional volume of 3.6 million m³/day 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 million m³/day in the Neuquina Basin at US$3.592/MBTU and 2.4 million m³/day 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 million m³/day 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 million m³/day 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 million m³/day at US$3.41/MBTU;
• Annual flat commitment from January 2024: 3 million m³/day at US$2.989/MBTU;
• Peak (winter) commitment from May 2024: 7 million m³/day at US$4.249/MBTU; and
• Peak (winter) commitment from May 2025: 7 million m³/day 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 million m³/day 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).

Pampa awards under Plan Gas.Ar

Pampa’s awards under each round are detailed below:

Note: 1 The total commitment from May 2021 is 7 million m³/day. Out of this, 4.9 are deliveries under Plan Gas.Ar and the balance is sold on the market. 2 1.25 adjustment factor in the winter and 0.82 for the rest of the year. 3 It covers May through September. 4 Prices start at US$9.8/MBTU and drop to US$6/MBTU in 2028

Notes: (1) 49.0 million m³/day is from the Neuquina Basin. Round 1’s base volume represents 70% of the total production commitment (96.3 million m³/day), and the remaining 30% is sold at market price. (2) Launched in August 2023 due to the delayed commissioning of the GPNK. (3)  Beginning postponed to 2023.

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. 4502/17). 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’ awarded price. ENARSA pays 100% of the Plan Gas’ awarded price.

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.

On January 28, 2025, the SE repealed the dispatch scheme established in SE Res. No. 354/20 as of February 1, 2025. The scheme prioritized dispatch per the obligations under ENARSA’s contracts with Bolivia and Plan Gas. As from March 1, 2025, it authorizes the recognition of fuel costs based on reference prices and declared and accepted CVP, including freight, natural gas transportation and distribution costs, and taxes and fees. CAMMESA will continue centralizing the fuel management of PPA under SE Res. No. 220/07, 21/17 and 287/17. Generators remunerated under spot energy will be able to manage their fuel, with CAMMESA as a last resort supplier (SE Res. No. 21/25). However, note NO-2025-16900682-APN-SE#MEC, sent by the SE to CAMMESA on February 19, 2025, establishes the new dispatch criteria as from March 1, 2025. The note allows generators to choose to manage their fuel to compete based on their declared CVP once CAMMESA has ensured the placement of the ToP volumes set under Plan Gas. This change could affect volumes between ToP and DoP committed under Plan Gas.

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, extendable to the winter period in case of oversupply at a specific basin, with 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 producing, processing, refining, marketing, storing and/or fractionating 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 gas resource availability 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. 1057/24).

As from 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 2024, the rate remained at 8%. Moreover, the Bases Law provided that the PEN may not intervene in domestic market sales for any segment in the hydrocarbon production chain.

DNU No. 277/22 facilitates access to FX in the MULC for companies with incremental production vs. 2021 to pay principal and interest on commercial and financial liabilities abroad and with non-resident affiliates, dividends from closed and audited balance sheets, and to repatriate direct investments by non-resident companies, transferable to direct suppliers.

For natural gas, the benefit equals 30% of the incremental injection valued at the country’s weighted average export price over the last 12 months, net of export duties. For oil, the benefit equals 20% of the quarterly incremental production at the average Brent quote over the previous 12 months, net of export duties and adjusted based on the crude oil quality.

On January 13, 2023, through Res. No. 13/23, the SE established the conditions for companies to access the regime. Through notes issued in August and September 2023, the Undersecretariat of Hydrocarbons granted Pampa the certificates to access the benefit for Q3 22, Q4 22 and Q1 23. Pampa submitted the applications from Q2 23 to date, which have not been granted.

To encourage oil and gas exports, in October 2023, SE Res. No. 808/23 allowed hydrocarbon exporters to settle transactions under the Export Growth Program (Programa de Incremento Exportador —PIE—, DNU No. 576/22). PIE partially recognizes exports under a differential blue-chip swap (CCL) rate and the remaining balance under the official FX. Pampa opted into this regime. In 2024, 20% of exports were settled under this regime (DNU No. 28/23).

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 allowed for a 10-year extension, but the Bases Law approved in July 2024 allows for a 20-year extension, extending the license until December 2047. On June 13, 2024, ENARGAS issued a favorable technical and legal report, highlighting TGS’s compliance with its obligations and authorizing ENARGAS’ comptroller, after the non-binding public hearing held on October 21, 2024, to submit his recommendation report to the PEN, which could finally issue the license extension executive order within 120 business days. This is expected to occur during the first half of 2025 once the affirmative recommendations by the various involved entities have been issued.

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.

Aiming to substitute gas oil and LNG imports with gas from Vaca Muerta, guaranteeing domestic supply and FX savings for the country, in June 2024, TGS submitted to the Federal Government a private initiative proposal on the GPM and an investment commitment in the regulated system, totaling an estimated US$700 million investment. The private initiative proposal, declared of public interest in December 2024 (DNU No. 1,060/24), envisages the expansion of GPM’s transportation capacity by 14 million m3 per day under the RIGI and as provided in the Hydrocarbons Law, with an estimated US$500 million investment and a US$200 million investment commitment in the regulated gas transportation system through the construction of 20 km of pipeline loops and the installation of 15,000 HP of compression in the Neuba II gas pipeline, expanding transportation capacity in the final sections by 12 million m3 per day. On February 25, 2025, the MECON delegated to the SE and ENARSA the responsibility to conduct the Private Initiative call for tenders, establishing the guidelines for drawing up the tender specifications (Res. No. 169/25). To date, the call for tenders has not been launched.

The Household Gas Bottles’ Program, effective since 2015, subsidizes the price of LPG gas bottles for low-income users (DNU No. 470/15 and amendments). TGS participates in this program, producing and selling a defined LPG quota at below-market reference prices:

Export duty

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 Brent price equals or exceeds US$60/bbl (DNU No. 488/20). In 2024, the rate remained at 8%.