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REGULATORY FRAMEWORK | 12 Months Ended
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Dec. 31, 2024
Regulatory Framework |
REGULATORY FRAMEWORK | NOTE 2: REGULATORY FRAMEWORK The main regulations applicable to the Company’s activities are detailed below. It is worth highlighting that this is not an exhaustive list of all regulations the Company is subject to. 2.1 Oil and gas 2.1.1 Argentine Hydrocarbons Law Law No. 27,007, enacted in 2014, amended Hydrocarbons Law No. 17,319, enacted in 1967, establishing the general principles for the exploration, exploitation, industrialization, transportation and commercialization of hydrocarbon resources in Argentina. The most relevant aspects are as follows:
| - | It empowers the Federal Government or the Provinces to grant exploration permits and concessions to the private sector.
| - | It establishes the terms for exploration permits: (i) conventional: term of 2 periods of up to 3 years each, plus 1 optional extension for up to 5 years; (ii) unconventional: term of 2 periods of 4 years each, plus 1 optional extension for up to 5 years; and (iii) on the continental shelf and in the territorial sea: term of 2 periods of 3 years each with the possibility of increasing by 1 year each.
| - | It sets the terms for exploitation concessions, renewable for 10-year terms: (i) conventional: 25 years; (ii) unconventional: 35 years; and (iii) on the continental shelf and in the territorial sea: 30 years.
| - | It establishes that transportation concessions will be granted for the same term as the originating exploitation concession.
| - | It fixes exploration and exploitation fee values for each km2 or fraction to be paid annually and in advance, and empowers the enforcement authority to set the payment of extension and exploitation bonds.
| - | It sets royalties of 12% (increasing up to a total maximum of 18% in the case of extensions) payable monthly to the grantor on the production of liquid hydrocarbons extracted at the wellhead and on natural gas production.
| - | It restricts the Federal Government and the Provinces from reserving new blocks in favor of public or mixed companies or entities, irrespective of their legal form, in the future.
Subsequently, Law No. 27,742, enacted in 2024, introduces additional amendments to Hydrocarbons Law No. 17,319 aiming to maximize income from the exploitation of resources, especially the following: (i) setting of commercialization prices in the domestic market without the PEN’s intervention; (ii) free international trade of hydrocarbons, in the absence of an objection by the SE; (iii) elimination of extensions to exploitation concessions; (iv) incorporation of authorizations to be granted by the PEN or the Provinces for hydrocarbon processing, conditioning or separation and natural gas liquefaction, not necessarily linked to an exploitation concession; (v) incorporation of standard tender specifications for new awards with a base value of 15% of royalties; (vi) setting of new royalty values payable in each stage regarding the average oil barrel price, annually adjustable based on the Brent price; and (vii) incorporation of authorizations to be granted by the PEN for underground storage of natural gas in natural reservoirs of depleted hydrocarbons. 2.1.1.1 CENCH in the Province of Neuquén The Ministry of Energy and Natural Resources of the Province of Neuquén established certain parameters for granting CENCH in this province, instrumented through Resolutions No. 53/20 and No. 142/21, and later ratified by Provincial Executive Order No. 2,183/21. These resolutions provide: (i) the development project’s parameters to apply for a CENCH, including a pilot plan of up to 5 years to demonstrate its technical and economic feasibility; (ii) the incorporation of the payment of a block extension bond for the surface exceeding that covered by the approved pilot plan; and (iii) the annual presentation of continuous development plans and investment commitments. 2.1.2 Gas Market 2.1.2.1 Argentine Natural Gas Production Promotion Plan (“GasAr Plan”) Executive Order No. 892/20 approved the Argentine Natural Gas Production Promotion Program (“GasAr Plan”) to promote the development of the Argentine gas industry based on a call for tenders mechanism. SE Resolution No. 317/20 launched the national public call for tenders under GasAr Plan 2020-2024 for the award of a 70 million m3 volume of natural gas per calendar year through the execution of specific contracts between gas producers, distributors and CAMMESA. Furthermore, the Federal Government bears the monthly payment of the difference between the price tendered and that resulting from the tariff schemes through a price complement to be paid directly to producers. Pursuant to SE Resolution No. 391/20, natural gas volumes were awarded under the GasAr Plan - Round 1 call for tenders, where the Company obtained a base volume of 4.9 million m3/day at an average annual price of US$ 3.60 MBTU for a term of 4 years as from January 1, 2021. Additionally, the Company was one of the three producers that offered an additional volume during the winter period, with the award of 1 million m3/day for US$ 4.68 MBTU, an essential volume to meet the Argentine demand’s high seasonality. Under SE Resolution No. 169/21, natural gas volumes offered under the GasAr Plan - Round 2 call for tenders where awarded, and the Company was awarded a volume of 0.70 million m3/day, 0.90 million m3/day and 1 million m3/day for the months of June, July and August-September 2021, respectively, as well as 0.86 million m3/day to meet the winter peak for years 2022 through 2024, for US$ 4.68 MBTU. SE Resolution No. 984/21 called for GasAr Plan - Round 3 for 2022 through 2024 inclusive, with injection starting in May 2022. The volumes were awarded by SE Resolution No. 1,091/21, and the Company was awarded 2 million m3/day for US$ 3.347 MBTU. Subsequently, Executive Order No. 730/22 established the 2023–2028 Reinsurance and Enhancement Plan for Federal Hydrocarbon Production, Internal Self-Sufficiency, Exports, Import Substitution, and Expansion of Transportation System for All Hydrocarbon Basins in the Country (the “Reinsurance Plan”) and modified the GasAr Plan scheme approved by Executive Order No. 892/20. The Reinsurance Plan establishes a new term for the regime until December 31, 2028, with the following main objectives: (i) consolidating a 70 MMm3/d flat block (volumes awarded under GasAr Plan’s Round 1 and 3), excluding winter peaks; and (ii) developing the demand for incremental volumes that may be evacuated with the new transportation capacity following the construction of the Francisco Pascasio Moreno Gas Pipeline (SE Resolution No. 326/24), previously called Néstor Kirchner Gas Pipeline (TransportAr Program, SE Resolution No. 67/22). SE Resolution No. 770/22, called for Tender Rounds 4 and 5 for the Neuquina Basin, and del Golfo and Austral Basins, respectively. Under SE Resolution No. 860/22, the Company was awarded with: (i) Round 4.1: the extension of the commitments under GasAr Plan - Rounds 1 and 3 until December 2028, maintaining the original prices of US$ 3.6 MBTU and US$ 3.347 MBTU, respectively; and (ii) Round 4.2: 4.8 million m3/day of the demand associated with flat gas for US$ 3.485 MBTU from July 1, 2023 until December 31, 2028. In December 2024, Pampa entered into agreements to extend the commitments under the contracts awarded in Rounds 1 and 3 of the Reinsurance Plan undertaken with CAMMESA and ENARSA, respectively. The awards granted to the Company and the executed contracts represented a production commitment of 15.7 million m3/day for the winter periods and 13.8 million m3/day for the summer periods 2023-2024, implying, compared to 2022, a 44% growth in winter production, the period with the largest gas supply needs in the country. As from 2025, the commitment under the Reinsurance Plan remains at 13.8 million m3/day. Finally, gas volumes under GasAr Plan - Round 5.2 were awarded pursuant to SE Resolution No. 799/23. The Company, jointly with all partners of the Aguaragüe Joint Venture, was awarded 400,000 m3/d of incremental volume to be sold to ENARSA for US$ 9.8 MBTU between October 2023 and December 2026 and US$ 6 MBTU between January 2027 and December 2028. The Company holds a 15% stake in this Joint Venture. 2.1.2.2 Accession to GasAr Plan’s payment cancellation scheme On June 19, 2024, the Company opted into the payment cancellation scheme established in Note NO-2024-54277417- APN-SE#MEC for the cancellation of compensations under the GasAr Plan. Consequently, it accepted (i) the provisional payment for the periods due February and March 2024, in cash, and (ii) the provisional payment for the periods due up to and including January 2024, and the adjusted payment for the periods due up to and including November 2023, through the delivery of government securities (BONO USD 2038 L.A.). The Company received cash for $ 2,884 million (US$ 3.1 million) and Bonds for $ 4,534 million FV (US$ 4.8 million) and recorded a $ 1,763 million (US$ 1.9 million) impairment in the related receivables considering the quoted market value of the instruments maturing in 2038 received under the described cancellation methodology. 2.1.2.3 Natural gas for the residential segment and CNG SE Resolutions No. 41/24, No. 93/24, No. 191/24, No. 232/24 and No. 284/24, SCEyM Resolution No. 18/24 and SE Resolutions No. 386/24 and No. 602/24 established the PIST price to be passed on to end users pursuant to the agreements entered into under the GasAr Plan for gas consumptions made as from the months of April, June and August through December 2024, respectively, and on the effective date of the tariff schemes published by ENARGAS. It is worth highlighting that the PIST value updates increase the amount collectable by the Company directly from distributors, decreasing the price compensation payable by the Federal Government under the GasAr Plan. 2.1.2.4 Acquisition of Natural Gas for Generation The power plant’s fuel supply is centralized in CAMMESA (except for generators with contracts under Energy Plus and under SE Resolution No. 287/17). Likewise, most gas supplies to CAMMESA are made under the GasAr Plan. Complementarily, CAMMESA launched biweekly calls to GasAr Plan’s awardees that may offer surplus volumes, with a maximum price equivalent to that awarded in GasAr Plan’s first round. During 2024, an average of 286 million m3/day at US$ 3.4 MBTU (168 million m3/day corresponding to the Neuquina Basin) were awarded in tenders for GasAr Plan’s awardees, and 87 million m3/day at US$ 2.4 MBTU (37 million m3/day of which correspond to the Neuquina Basin) under complementary calls. 2.1.2.5 Natural Gas and Liquefied Natural Gas Exports (i) Natural Gas Current regulations establish a procedure to authorize natural gas exports delimiting four export zones: the Neuquina Basin and the Austral Basin, with summer quotas, and the Noroeste Basin and other zones, with no quota definition. The distribution of firm summer quotas among producers is made considering (i) the share of the producer’s volume in the basin’s total volume, and (ii) the highest discount in the weighted-average price discount per volume against the basin’s incremental volume. For the summer periods (January - April and October - December), an export quota of 9 million m3/d for the Neuquina Basin and 2 million m3/d for the Austral Basin was assigned, with a minimum price equal to the simple average of the Brent crude quotations for the first fifteen days of the month prior to delivery, multiplied by 7% and 5.5% for the 2024 and 2025 summer periods, respectively. The Company was assigned a volume of 606,529 m3/d and 977,963 m3/d for the 2024 and 2025 summer periods, respectively. In addition, the SE established the export quotas for the winter period (May - September) for a total of 5.9 m3/d and 7 million m3/d for the 2024 and 2025 winter periods, respectively. In line with its participation in the GasAr Plan, the Company was assigned a volume of 610,989 m3/d and 694,236 m3/d for the 2024 and 2025 winter periods, respectively. It is worth highlighting that, as of the date of issuance of these Consolidated Financial Statements, there is an 8% tax on natural gas exports. (ii) Liquefied Natural Gas (LNG) Law No. 27,742 (amending Law No. 24,076), establishes a special LNG export regime for entities producing, processing, refining, commercializing, storing and/or fractionating hydrocarbons and/or their derivatives, subject to non-objection by the SE within 120 business days. The granted LNG export authorizations will be final regarding the LNG volumes authorized for a term of up to 30 years from the commissioning of the liquefaction plant (on land or floating) or its expansions. 2.1.3 Oil market 2.1.3.1 Crude oil price As of December 31, 2024, there is no reference price for the sale of crude oil in the domestic market. However, considering pump prices for fuels, local refining companies have historically validated prices below the export parity. As with natural gas exports, there is an 8% export duty on crude oil. 2.2 Generation 2.2.1 Generation units Generation units are remunerated under: i) sales contracts with large users within the MAT (SE Resolutions No. 1,281/06 and No. 281/17); ii) supply agreements with CAMMESA (SE Resolutions No. 220/07, No. 21/16, No. 287/17 and Renovar Programs) and iii) sales to the spot market pursuant to WEM’s regulations (SE Resolution No. 387/24 in force in force at the end of the year and complementary resolutions). The Company’s generating units, held directly and through its subsidiaries and joint ventures, are detailed below:
Schedule of generating units in operation |  |  |
In operation as of 12.31.2024: |  |  |
Generator | Generating unit | Tecnology | Power | Applicable regime (1)
CTG | GUEMTG01 | TG | 100 MW | Energy Plus Res. No. 1,281/06
CTG | GUEMTV11 | TV | ≤100 MW | Resolution No. 387/24
CTG | GUEMTV12 | TV | ≤100 MW | Resolution No. 387/24
CTG | GUEMTV13 | TV | >100 MW | Resolution No. 387/24
Piquirenda | PIQIDI 01-10 | MCI | 30 MW | Resolution No. 387/24
CPB | BBLATV29 | TV | >100 MW | Resolution No. 387/24
CPB | BBLATV30 | TV | >100 MW | Resolution No. 387/24
CT Ing. White | BBLMD01-06 | MCI | 100 MW | Resolution No. 21/16
CTLL | LDLATG01/TG02/TG03/TV01 | CC | >150 MW | Resolution No. 59/23
CTLL | LDLATG04 | TG | 105 MW | Res. No. 220/07 (75%)
CTLL | LDLATG05 | TG | 105 MW | Resolution No. 21/16
CTLL | LDLMDI01 | MCI | 15 MW | Resolution No. 387/24
CTGEBA | GEBATG01/TG02/TV01 | CC | >150 MW | Resolution No. 59/23
CTGEBA | GEBATG03 | TG | 169 MW | Energy Plus Res. No. 1,281/06
CTGEBA | GEBATG03/TG04/TV02 | CC | 400 MW | Resolution No. 287/17
Ecoenergía | CERITV01 | TV | 14 MW | Energy Plus Res. No. 1,281/06
CT Parque Pilar | PILBD01-06 | MCI | 100 MW | Resolution No. 21/16
CTB | EBARTG01 - TG02 | TG | >50 MW | Resolution No. 59/23
CTB | EBARTV01 | TV | 279 MW | Resolution No. 220/07
HIDISA | AGUA DEL TORO | HI | HI – Media 120<P≤300 | Resolution No. 387/24
HIDISA | EL TIGRE | HR | Renewable ≤ 50 | Resolution No. 387/24
HIDISA | LOS REYUNOS | HB | HB – Media 120<P≤300 | Resolution No. 387/24
HINISA | NIHUIL I - II - III | HI | HI – Small 50<P≤120 | Resolution No. 387/24
HPPL | PPLEHI | HI | HI – Media 120<P≤300 | Resolution No. 387/24
PEPE II | PAMEEO | Wind | 53 MW | MATER Res. No. 281/17
PEPE III | BAHIEO | Wind | 53 MW | MATER Res. No. 281/17
PEPE IV | PEP3EO - PE32EO | Wind | 81 MW | MATER Res. No. 281/17
PE Arauco (PEPE V) | AR21EO | Wind | 99.75 MW | Renovar
PEPE VI | PEP6EO | Wind | 139.5 MW | MATER Res. No. 281/17
(1) |  | Surplus power capacity and energy are remunerated in the spot market.
2.2.2 Sales contracts with large users within the MAT 2.2.2.1 Energy Plus SE Resolution No. 1,281/06 set a specific regime for new generation installed by certain agents, authorizing the execution of Energy Plus contracts in the MAT at a price to be negotiated with the GU300 above the base demand (electricity consumption for the year 2005). Under this regime, the Company —through its power plants CTG, EcoEnergía and CTGEBA, sells its energy and power capacity for a maximum amount of 283 MW with Energy Plus contracts mostly denominated in U.S. dollars, or adjusted by CAMMESA’s price variation instead. In addition, the Company has power availability agreements in force with other Energy Plus generators whereby, in case of unavailability, it purchases or sells power to support the respective agreements. It is worth highlighting that SE Resolution No. 21/25 introduces modifications limiting the validity of the Energy Plus regime (see Note 23). 2.2.2.2 Renewable Energy Term Market (“MATER” Regime) SE Resolution No. 281/17 regulated the regime for large users and WEM distribution agents’ large demands (comprised within Section 9 of Law No. 27,191) to meet the obligation to supply their demand from renewable sources through individual purchases within the MATER, upon conditions to be agreed between the parties. Under this provision, the Company, through its PEPE II, III and IV wind farms, sells energy for up to 187 MW, and in 2024 it added power capacity for 140 MW through PEPE VI (with 31 wind turbines commissioned between July and November 2024); furthermore, sales started for third-party generators’ renewable energy for an approximate volume of 1.14 MW. Surplus energy is sold in the spot market. 2.2.3 Supply Agreements with CAMMESA 2.2.3.1 SE Resolution No. 220/07 SE Resolution No. 220/07, authorized CAMMESA to enter into long-term agreements with WEM generating agents for the energy produced with new equipment and prices that remunerate the investments made by the agent at a rate of return to be accepted by the SE. Within the framework of this resolution, the Company has units remunerated under agreements for 79 MW and 280 MW, through CTLL thermal power plant and CTEB´s closed cycle, owned by CTB, respectively. 2.2.3.2 SE Resolution No. 21/16 SE Resolution No. 21/16 called for parties interested in offering new thermal power generation capacity with the commitment to making it available through the WEM for the 2016/2017 summer, 2017 winter, and 2017/2018 summer periods. For the awarded projects, wholesale power purchase agreements were entered into with CAMMESA for a term of 10 years, with a remuneration made up of the available power capacity price plus the variable non-fuel cost for the delivered energy and the fuel cost (if appropriate), less penalties and fuel surpluses. Pursuant to this resolution, the Company, through its CTLL, CTIW and CTPP power plants, has effective agreements with CAMMESA for the sale of energy and power capacity for a total 305 MW. Surplus power capacity is sold in the spot market. 2.2.3.3 SE Resolution No. 287/17 SE Resolution No. 287/17 launched the call for tenders for low specific consumption, cogeneration and CC closing projects on existing equipment, provided the new capacity does not increase electricity transmission needs or includes the necessary expansions at the tenderer’s cost. Pursuant to this regulation, the Company, through its CTGEBA thermal power plant, has entered into a wholesale power purchase agreement with CAMMESA for the sale of energy and power capacity for a total 400 MW, for a term of 15 years. 2.2.3.4 Renovar Programs In order to meet the objectives, set by Law No. 26,190 and Law No. 27,191 promoting the use of renewable sources of energy, the MEyM called for open rounds for the hiring of electric power from renewable sources (Renovar Programs). For the awarded projects, renewable electric power supply agreements were executed for the sale of an annual committed electric power block for a term of 20 years. Under the Renovar programs, the Company, has a supply contract in place with CAMMESA for a total of 100 MW for the PE Arauco. 2.2.4 Remuneration at the spot market Spot generation is remunerated with tariffs in pesos that are updated through the issuance of different resolutions. For fiscal year 2024, SE Resolutions No. 9/24, No. 99/24, No. 193/24, No. 233/24 and No. 285/24, SCEyM Resolution No. 20/24 and SE Resolution No. 387/24 provided for 73.9%, 25%, 3%, 5%, 2.7%, 6% and 5% increases as from the February, June and August through December 2024 economic transactions, respectively. Subsequently, SE Resolutions No. 603/24 and No. 27/25 provided for 4% increases as from the January and February 2025 economic transactions, respectively. Likewise, the maximum spot price in the WEM was updated to $ 12,469/MWh as from February 2025. The applicable remuneration based on technology as of December 31, 2024 under SE Resolution No. 387/24 is detailed below. 2.2.4.1 Remuneration for Available Power Capacity 2.2.4.1.1 Thermal Power Generators A minimum remuneration for power capacity based on technology and scale was established, and generating, co-generating and self-generating agents owning conventional thermal power plants were allowed to offer guaranteed availability commitments for the energy and power capacity generated by their units and not committed under sales contracts with large users within the MAT or supply agreements with CAMMESA. Availability commitments are tendered for quarterly periods: a) summer (December through February); b) winter (June through August) and c) ‘other,’ (March through May, and September through November), the thermal generators’ remuneration for committed power capacity being proportional to their compliance. The minimum remuneration for generators with no availability commitments includes the following scales and prices:
Schedule of minimum remuneration to thermal generators |
Technology / Scale | ($ / MW-month)
Large CC Capacity > 150 MW | 1,659,023
Large TV Capacity > 100 MW | 2,366,144
Small TV Capacity ≤ 100 MW | 2,828,486
Large GT Capacity > 50 MW | 1,930,992
The remuneration for guaranteed power capacity to generators with availability commitments is:
Schedule of remuneration for thermal generators with guaranteed power capacity |
Period | ($ / MW-month)
Summer – Winter | 5,933,881
Fall - Spring | 4,450,412
2.2.4.1.2 Hydroelectric Generators Power capacity availability is determined independently of the reservoir level, the contributions made, or the expenses incurred. In the case of pumping hydroelectric power plants, the operation as turbine and pump is considered to calculate availability. The base remuneration includes the following scales and prices:
Schedule of hydroelectric generators by technology and scales values |
Technology / Scale | ($ / MW-month)
Medium HI Capacity > 120 ≤ 300 MW | 2,175,761
Small HI Capacity > 50 ≤ 120 MW | 2,991,666
Medium Pumped HI Capacity > 120 ≤ 300 MW | 2,175,761
Renewable HI Capacity ≤ 50 MW | 4,895,454
The payment for power capacity is determined by the actual capacity, hours of unavailability due to programmed and/or agreed maintenance are not computed for the calculation of the remuneration. However, to consider the incidence of such programmed maintenance works, a factor of 1.05 is applied over the power capacity payment. In the case of hydroelectric power plants maintaining control structures on river courses and not having an associated power plant, a 1.20 factor is applied to the plant at the headwaters. 2.2.4.2 Remuneration for generated and operated energy The following remunerations were established:
Schedule of generated and operated energy thermal units remuneration |  |  |
Remuneration | Thermal Power Plants ($ / MWh) | Pumped Hydropower Plants ($ / MWh) | Non-conventional Source ($ / MWh)
Generated energy | Between 3,960 and 6,929 | 3,462 | 27,691
Operated energy | 1,378 | 1,378 | -
In the case of thermal generators, the remuneration for generated energy depends on the type of fuel. Furthermore, it is worth highlighting that if the dispatched unit operates outside its optimal dispatch, the remuneration for generated energy is recognized at 60% of the installed net capacity, irrespective of the energy delivered by the unit. The remuneration for operated energy corresponds with the grid’s optimal dispatch; however, the current resolution does not indicate the consequence if this is not the case. Likewise, in the case of pumped hydropower plants, both the generated energy and that used for pumping are considered. Additionally, if it operates as a synchronous condenser, $986/MVAr is recognized in addition to the price for the energy operated. Energy generated from non-conventional energy sources (including wind energy) has a remuneration equivalent to the integration of the hours of the month at a price of $ 29,951/MWh. This remuneration is reduced to 50% in the case of energy generated prior to the commercial commissioning by the Agency in Charge of Dispatch. 2.2.4.3 Additional remuneration As from November 2022, a differentiated remuneration scheme was established for energy generated during peak hours, applicable to thermal and hydroelectric generators, with a value equivalent to twice the value of the current price of energy generated during peak hours (6:00 p.m. to 11:00 p.m.) every day of the months of December, January, February, June, July and August, and one time such value for the same hours of the months of March, April, May, September, October and November. 2.2.4.4 Remuneration for CC SE Resolution No. 59/23 established a regime allowing for the execution of availability and efficiency improvement agreements with CAMMESA for the adhered CC owners. The agreements imply an availability commitment of 85% of the net power for a maximum term of 5 years, a US$ 2,000/MW-month remuneration for the power capacity made available, and the dollarization of the energy price based on the fuel used (US$ 3.5/MWh in the case of natural gas and US$ 6.1/MWh in the case of fuel oil and gas oil). Additionally, for generators with availability commitments in the spot market, it implies a 35% and 15% reduction in the remuneration to be received for the guaranteed power capacity for the summer-winter and autumn-spring periods, respectively. The Company executed agreements with CAMMESA for its CTLL and GTGEBA power plants’ CC. Additionally, CTB executed an agreement with CAMMESA for its open cycle’s GT units. The mentioned agreements are effective from March 1, 2023 to February 29, 2028. 2.2.4.5 Additional, complementary and exceptional remuneration for thermal generation Regarding power generation, SE Resolution No. 294/24 incorporated a scheme recognizing an additional, complementary and exceptional remuneration to promote thermal generation plants’ availability in critical months and hours, effective from December 2024 to March 2026. This additional remuneration may be extended by the SE’s Under-secretariat of Electric Power for an additional 12-month period subject to the presentation of a maintenance program for each generation unit. The remuneration scheme implies (i) a US$ 2,000/MW-month remuneration for power capacity, adjusted by a criticality factor that considers the node where the generation unit is located, and by the unit’s actual availability in the most critical hours, and a 50% of such remuneration for the power capacity exceeding the committed one; and (ii) a remuneration for the energy generated in the most critical days and hours, also adjusted by the criticality factor, ranging from US$ 3.4/MWh to US$ 10.5/MWh depending on the fuel and the generation technology used. On its part, CAMMESA must implement an exceptional dispatch procedure allowing for the strategic use of the power generation units to reduce the risks of supply restrictions during peak consumption periods, including the possibility of reserving the dispatch of the remaining operating hours of units nearing the end of their useful life to leverage their use during the SADI’s peak demand times. Under this regulation, the Company adhered to the call and formalized availability agreements for the energy of its thermal power plants CPB, CTG, Piquirenda, CTLL, CTGEBA and Ecoenergía not committed under other regimes. 2.2.4.6 Suspension of contracts within the MAT As of December 31, 2024, the suspension of contracts within the MAT (excluding those derived from a differential remuneration scheme) remained in effect. Subsequently, SE Resolution No. 21/25 introduced regulatory amendments (see Note 23). 2.2.5 Fuel supply for thermal power plants Pursuant to Ministry of Productive Development’s Resolution No. 12/19, the supply of fuels for power generation is centralized in CAMMESA (except for generators under the Energy Plus scheme or with contracts under SE Resolution No. 287/17). Likewise, as a result of GasAr Plan’s implementation (see Note 2.1.2.1), SE Resolution No. 354/20 established a new dispatch order for generation units based on the fuel supplied for their operation according to a centralized dispatch scheme, and established that the electricity demand should bear, among others, the regulated transportation costs, the cost of natural gas and the corresponding take-or-pay obligations. On its part, generating agents that maintained the possibility of contracting their fuel supply (i.e., agents under the Energy Plus program or with contracts under SE Resolution No. 287/17) could opt into CAMMESA’s unified dispatch through the operational assignment of the contracted gas and firm transportation volumes and the waiver to file claims regarding the application of SE Resolution No. 354/20, which impacts on the assigned priority order. In the specific case of generators with wholesale power purchase agreements under SE Resolution No. 287/17, it was provided that they would have the option of canceling the self-supply obligation and the resulting recognition of its associated costs, having to maintain the respective transportation capacity for its management in the centralized dispatch. The Company assigned the firm transportation and gas volumes committed to supplying Genelba Plus’ CC and Energy Plus contracts, setting certain guidelines for calculating fuel costs to support its Energy Plus contracts. In the case of the supply to Genelba Plus’ CC, the assignment will remain effective during the life of the GasAr Plan, and it may be revoked by the generator with a minimum advance notice of 30 business days. Within this framework, the parties agreed to enter into an addendum to the wholesale power purchase agreement to establish the modifications regarding this new supply scheme, which execution is pending as of the issuance of these Consolidated Financial Statements. It is worth highlighting that SE Resolution No. 21/25 abrogates the above-mentioned dispatch scheme (see Note 23). 2.2.6 Payment agreement with CAMMESA On May 27, 2024, an agreement was entered into with CAMMESA instrumenting the exceptional, transitional and unique payment system established in SE Resolution No. 58/24 for the balance of WEM’s unpaid economic transactions. Thus, the December 2023 and January 2024 transactions were canceled through the delivery of government securities (BONO USD 2038 L.A.); whereas the February 2024 transaction was paid in cash with funds available in CAMMESA and transfers made by the Federal Government. In all cases, payments were made without recognizing interest. The Company received Bonds for $ 73,776 million FV (US$ 82.6 million) and $ 51,473 million in cash (US$ 57.8 million), and recorded a $ 46,485 million (US$ 53.5 million) impairment in CAMMESA’s receivables considering the received instrument’s market value and the non-recognition of interest under the described cancellation methodology. 2.3 Gas Transportation 2.3.1 TGS’s Tariff situation PEN Executive Order No. 55/23 dated December 16, 2023 declared the emergency of the national energy sector until December 31, 2024, date which was postponed until July 9, 2025 under PEN Executive Order No. 1,023/24 dated November 19, 2024. Among other issues, it: (i) launches the Five-Year Tariff Review (“FTR”) process, (ii) establishes ENARGAS’ intervention as from January 1, 2024, and (iii) instructs the SE to issue the necessary rules and procedures to pass market prices for the natural gas transmission utility. PEN Executive Order No. 1,023/24 provides that tariff schemes resulting from the tariff review launched under PEN Executive Order 55/23 must not exceed July 9, 2025. On March 26, 2024, TGS entered into the 2024 transitional agreement (“RTT24”) with ENARGAS, which established a transitional 675% update in natural gas transportation tariffs. This tariff increase entered into effect on April 3, 2024, following the publication of ENARGAS Resolution No. 112/24 in the BO. Under this Resolution, as from May 2024 and until the FTR process’ completion, tariffs would be adjusted monthly by a transitional update index. However, on May 9, June 5 and July 1, 2024, ENARGAS informed the licensees of the natural gas transportation and distribution utility of the postponement of the above-mentioned monthly tariff adjustment for the months of May, June and July 2024, maintaining tariff schemes in force as from April 3, 2024. Furthermore, ENARGAS communicated the replacement of the tariff update index based on the expected inflation to be estimated by the Ministry of Economy. Subsequently, effective as from August 1, September 2, October 1, November 4, December 4, 2024, January 1 and February 1, 2025, ENARGAS published new transitional tariff charts with 4%, 1%, 2.7%, 3.5%, 3%, 2.5% and 1.5% increases, respectively, over the current tariffs. It is worth highlighting that the operation of gas pipelines by TGS requires a high level of investments related to the service’s quality, safety and reliability. This is why it is important to determine the tariff for the public natural gas transportation service on the basis of an economic, prudent and efficient operation, allowing for deriving sufficient income to provide a sustainable, safe and reliable service. Within the framework of the FTR process, on February 6, 2025 a public hearing was held to consider, among other issues, the FTR and the periodic update methodology for gas transportation and distribution tariffs. TGS presented, among others, its costs and investment plan for the five-year period 2025-2030, the capital base, a proposed WACC of 9.98% real after taxes, requested a tariff increase of 22.7% with respect to the rates in force as of January 2025, and presented alternative tariff adjustment methodologies (IPIM or formula). On the other side, the ENARGAS proposed the application of a 7.18% real after taxes WACC and a periodic tariff adjustment (50% CPI and 50% IPIM). As of the date of issuance of these Consolidated Financial Statements, the resolution providing for the FTR’s conclusion, granting the corresponding tariff update and providing the framework for the development of the natural gas transportation activity over the 2025-2030 five-year period has not been issued. 2.3.2 License extension request On September 8, 2023, TGS submitted a request to ENARGAS to initiate a license term extension proceeding, for the provision of the gas transportation service contemplating all the scopes of the license approved by Executive Order No. 2,458/92, as of the expiration that will operate on December 28, 2027. On June 13, 2024, ENARGAS issued a technical and legal report indicating that TGS has amply complied with its obligations under the License. This report allows the ENARGAS comptroller, after the non-binding public hearing held on October 21, 2024, to issue its recommendation report to be submitted to the PEN, which in turn could issue the executive order granting the License’s 20-year extension within 120 working days. As of the date of issuance of these Consolidated Financial Statements, the PEN executive order granting the extension is pending issuance, which is expected to be issued during the first half of 2025, after giving intervention to the different public bodies. 2.3.3 Regulatory framework of the segment of Production and Commercialization of Liquids 2.3.3.1 Domestic market The production and commercialization of liquids segment is not subject to regulation by ENARGAS. However, over recent years, the Argentine Government enacted regulations which significantly impacted it. LPG domestic sales prices are impacted by the provisions of Law No. 26,020 "Regime of the industry and commercialization of liquefied petroleum gas" and the Argentine Government through the public office in charge, that set forth LPG minimum volumes to be sold in the local market in order to guarantee domestic supply. In this context, TGS sells the production of propane and butane to fractionators at prices determined semiannually. Decree No. 470/15, regulated by SE Resolution No. 49/15, created the “Household Plan” and sets a maximum reference price for the members of the commercialization chain in order to guarantee the supply to low-income residential users, by committing the LPG producers to supply at a fixed price with a quota assigned to each producer. TGS has filed various administrative and judicial claims challenging the general regulations of the program, as well as the administrative acts that determine the volumes of butane that must be sold in the domestic market, in order to safeguard its economic-financial situation and thus, preventing that this situation does not extend over time. As from January 24, 2025, SE Resolution No. 15/25 eliminates the maximum sales price set for the products provided under the Household Plan (being the export parity price published by the SE under Law No. 26,020 the limit sale price). Moreover, although this resolution maintains LPG producers’ obligation to supply the domestic market, it eliminates the previously effective product supply contributions. In addition, TGS is a party of the Propane Gas Supply Agreement for Induced Propane Gas Distribution Networks ("Propane for Networks Agreement") entered into with the Argentine Government and propane producers by which it undertakes to supply propane to induced propane gas distributors and sub- distributors through at a price lower than the market price. In compensation, TGS receives an economic compensation calculated as the difference between the sale price and the export parity determined by the SE. As of December 31, 2024, the Argentine Government owes TGS $ 10,881 million under these items. 2.3.3.2 Foreign market The rate applicable to the export duties for certain gas and oil derivatives, including the products produced and exported by TGS, is 8%. During 2024, TGS participated in the Export Increase Program (see Note 2.6.4). 2.4 Transmission 2.4.1 Transener and Transba tariff situation PEN Executive Order No. 55/23, dated December 16, 2023, declared the emergency in the national energy sector until December 31, 2024, date extended until July 9, 2025 by PEN Decree No. 1,023/24 of November 19, 2024. Among other issues, it is established (i) the launching of the tariff review process in accordance Article 43 of Law No. 24,065 for public electricity distribution and transmission companies under federal jurisdiction and (ii) that the entry into force of the resulting tariff schedules could not exceed July 9, 2025. Through ENRE Resolutions No. 104/24 and No.105/24, hourly remuneration values effective as from February 19, 2024 (date of publication in the BO) were established, which represented an increase of 179.7% and 191.1% compared to the values in force since November 2023 for Transener S.A. and Transba S.A., respectively. Furthermore, the tariff update formula to be applied monthly as from May 2024 was determined. However, by instruction of the Ministry of Economy, on May 9, June 11 and July 2, 2024, the ENRE informed Transener S.A. and Transba S.A. of the suspension of the tariff update planned for the months of May, June and July 2024, and modified the update mechanism with a formula based on the inflation projected for the July-December 2024 semester. These measures were emphatically rejected by both companies due to the great impact on the income necessary to render the service, the uncertainty on the methodology and the lack of definition on the source of the involved indexes, and they requested the ENRE to take all the necessary measures to restore income. Subsequently, effective as from August 1, September 1, October 1, November 1, December 1, 2024, and January 1 and February 1, 2025, the ENRE determined hourly remuneration values, establishing 6%, 6%, 2.7%, 6%, 5%, 4% and 4% increases over effective values for Transener S.A. and Transba S.A. Moreover, on April 15, 2024, ENRE Resolution No. 223/24 approved the “Program for the tariff review of electric power transmission in 2024”, which set the criteria and methodology for the five-year tariff review process to be taken into consideration by transmission companies when submitting their tariff proposal applicable as from January 1, 2025. In this sense, the information on the capital base, historical costs, property, plant and equipment, status of easements and existing facilities was submitted to the ENRE in due time and form before May 17, 2024, whereas the projected information on costs, investments and required annual remuneration was sent to the ENRE on September 16, 2024. On August 21, 2024, ENRE Resolution No. 554/24 set the high-voltage and main electricity distribution utility concessionaires’ return rate for the 2025-2029 period at 10.14% after taxes. On October 3, 2024, ENRE Resolution No. 706/24 launched the procedure for determining the remuneration of independent transmission companies, to be applied as of January 1, 2025, including Transener S.A., as operator of the Fourth Line and the Choele Choel - Pto. Madryn Interconnection, and Transba S.A., for the Transportista Independiente de Buenos Aires (TIBA)’s facilities. Subsequently, ENRE Resolutions No. 5/25 and No. 7/25 dated January 7, 2025 modified the schedule, contemplating the submission of the required annual remuneration before January 20, 2025 and the entry into effect of the resulting tariff schemes by April 1, 2025. Besides, on January 10, 2025, ENRE Resolution No. 28/25 modified the high-voltage and main electricity distribution utility concessionaires’ return rate defined by ENRE Resolution No. 554/24 to 6.10% after taxes. Transener S.A. and Transba S.A. will file the corresponding appeal for reconsideration since the reasonable profitability requirement mandated by Law No. 24,065 is not complied with. In this sense, and according to the modified tariff review schedule, on January 20, 2025, Transener S.A. and Transba S.A. ratified their required tariffs, considering a 10.14% profitability rate. Finally, on January 21 and 28, 2025, ENRE Resolutions No. 74/25 and No. 80/25 called for a Public Hearing on the tariff proposals submitted by Transmission Companies and Independent Transmission Companies, to be held on February 25 and 26, 2025, respectively. 2.5 Regulations on access to the MLC In 2020, BCRA introduced measures with the purpose of regulating inflows and outflows in the MLC to maintain the exchange rate stability and protect international reserves in view of the high degree of uncertainty and volatility in the exchange rate, including restrictions associated with transactions with stock market assets by companies and the disposal of liquid foreign assets. All foreign currency demand transactions in the MLC require BCRA’s prior authorization, with certain exceptions, such as: (i) in case of an affidavit stating that all foreign currency holdings in the country are deposited in local financial entities and that there are no liquid foreign assets available for an amount greater than US$ 100,000; (ii) in case of deferred payment of certain imports of goods with customs entry registration; (iii) in case of payment of services rendered by non-residents; (iv) in case of an affidavit stating that, on the date of access to the MLC and in the previous 90 days, certain sale, exchange or securities transfer transactions were not entered into, with the commitment not to enter into such transactions during the 90 days following the request for access to the MLC. In addition, the BCRA imposes, in certain circumstances, the obligation to enter and settle funds received abroad within 20 business days from collection or receipt. It is worth highlighting that the detailed information does not list all possibly applicable exchange regulations; for more information on Argentina’s exchange rate policies, please visit the Central Bank’s website: www.bcra.gov.ar. 2.6 Tax regulations 2.6.1 Income tax 2.6.1.1 Income tax rate Law No. 27,630, effective in Argentina for fiscal years beginning on or after January 1, 2021, established a tiered rate scheme of 25%, 30% and 35% and, if applicable, a flat tax depending on the level of annual net taxable income. The income tax rates used at year-end in Argentina, Ecuador, Bolivia, Uruguay and Chile are 35%, 25%, 25%, 25% and 27%, respectively. A 3% surcharge on income tax will be added in Ecuador when the shareholder is an entity incorporated in a jurisdiction considered a tax haven under Ecuadorian law. In Uruguay, effective January 1, 2023, the Income Tax on Economic Activities (IRAE) includes as Uruguayan-source income certain passive income obtained by entities making up multinational groups and considered non-qualified. 2.6.1.2 Tax on dividends Law No. 27,430 and modifications introduced by Law No. 27,541 and Law No. 27,630, established a 7% tax on dividends derived from earnings accrued during fiscal years beginning as from January 1, 2018, which be distributed by Argentine companies to individuals, undivided estates or beneficiaries residing abroad. Dividends resulting from benefits gained until the fiscal year prior to that beginning on January 1, 2018, in Argentina, will remain subject to the 35% withholding on the amount exceeding the untaxed distributable retained earnings (equalization tax’ transition period) for all beneficiaries. In Bolivia, payments of Bolivian-source income made to foreign beneficiaries are subject to a 12.5% withholding tax on the profits of the foreign beneficiary companies. In Ecuador, effective January 1, 2020, dividends distributed to foreign shareholders are subject to a 10% withholding tax. In Chile, dividend payments to non-residents are subject to a 35% withholding tax. In Uruguay, dividends distributed by IRAE taxpayers are taxed —until the concurrence of the net income taxed by IRAE—, at a general 7% rate, while the amount of a company’s taxable income that remains undistributed after 3 fiscal years is treated as a deemed distribution and is subject to the 7% dividend tax. 2.6.1.3 Tax inflation adjustment Law No. 27,430 sets out the following rules for the application of the income tax inflation adjustment mechanism:
| (i) | a cost adjustment for goods acquired or investments made during fiscal years beginning after January 1, 2018 taking into consideration the percentage variations in the CPI published by the INDEC; and
| (ii) | the application of the adjustment provided for by Title VI of the Income Tax Law when variations in the above-mentioned index exceed 100% over the 36 months preceding the closing of the fiscal period to be settled.
Law No. 27,541 provided that, as regards the positive or negative fiscal inflation adjustment determined as a result of the application of the adjustment provided for by Title VI of the Income Tax Law corresponding to the first and second fiscal year starting as from January 1, 2019, one-sixth should be charged in that fiscal period and the remaining five sixths, in equal parts, in the five immediately following fiscal periods. On December 1, 2022, Law No. 27,701 was published in the BO, which established that taxpayers determining a positive inflation adjustment in the first and second fiscal year starting from January 1, 2022 (inclusive) may allocate one-third in that fiscal period and the remaining two-thirds, in equal parts, in the two immediately following fiscal periods. This computation only applies to subjects making investments in the purchase, construction, manufacture, production or final import of property, plant and equipment, except automobiles, during each of the two fiscal periods immediately following that in which the computation of the first third of the period in question exceeds or equals $ 30,000 million. As of issuance of these Consolidated Financial Statements, this provision has not yet been regulated. The Company and its subsidiaries determine and disclose the impact of the tax inflation adjustment for each of the fiscal periods in which it is applicable. 2.6.2 Value-added tax A procedure is established for the reimbursement of tax credits originated in investments in property, plant and equipment which, after 6 months as from their assessment, have not been absorbed by tax debits generated by the activity. 2.6.3 Tax for an Inclusive and Caring Argentina (Impuesto Para una Argentina Inclusiva y Solidaria, “PAIS”) for import and foreign service procurement transactions PEN Executive Order No. 377/23, dated July 24, 2023, extended the application of the PAIS tax to the acquisition of services abroad and import transactions for certain goods, exempting the following goods associated with the energy sector under SE Resolutions No. 671/23, 714/23, 824/23 and 955/23: (i) liquid fuels, natural gas and electricity;; (ii) goods destined for the construction and commissioning of the Perito Francisco Pascasio Moreno Gas Pipeline, the Northern gas pipeline reversal project and works making up the Gas Pipelines System Program; (iii) goods destined for power generation works with or without foreign financing for the payment of imports; (iv) goods for works and maintenance of renewable energy generation projects, including PEPE II through IV wind farms, PE Arauco and PEPE VI; and (v) maintenance and construction works at thermal and hydroelectric power plants, including the Company’s assets. For non-exempted goods and services, AFIP Resolution No. 5,393/23, dated July 25, 2023, provided for an advance payment offsetable against the PAIS tax equivalent to 95% of the total final tax payable for certain goods and merchandise. This advance payment had to be paid by the importer when declaring the import’s intended use. The PAIS tax’s remaining 5% balance had to be paid when accessing the MLC to make the payment abroad, with the intervening bank acting as collection and settlement agent. The application of the PAIS tax on the acquisition of services abroad and non-exempted import operations ceased to be in force as of December 23, 2024. 2.6.4 Export Increase Program On October 3, 2023, SE Resolution No. 808/23 temporarily included the products sold by the Company, among other exports, under the Export Increase Program created by PEN Executive Order No. 576/22. Consequently, a certain minimum percentage of the value of exports in foreign currency had to be entered and settled in the MLC, and the remaining percentage could be settled in pesos through the purchase of marketable securities for exports settled during the periods established by the regulations. Finally, PEN Executive Order No. 28/23 established, as from December 13, 2023, the entry and settlement of at least 80% of the value of foreign currency exports. 2.6.5 Other regimes Law No. 27,742 created the RIGI, which grants tax, customs and exchange benefits for projects involving investments in long-term assets according to a determined amount per productive sector (from US$ 200 to US$ 600 million) or if the investments qualify as a long-term strategic export project (US$ 2 billion) aiming to encourage major domestic and foreign investments, promote the competitiveness of economic sectors, generate predictability and certainty conditions, increase goods and services exports, advance job creation and further the development of local production chains. Additionally, Law No. 27,743, “Palliative and Relevant Tax Measures Act”, enacted on July 8, 2024, establishes an Exceptional Tax, Customs and Social Security Obligations Regularization Regime for obligations due as of March 31, 2024, establishing the reduction of compensatory interest depending on the time and form of adhesion, the total remission of fines and the discharge of criminal penalties that may apply to such obligations. It is worth highlighting that, during the third quarter of 2024, the Company paid $ 901 million, including items under discussion with tax authorities, within the framework of the above-mentioned regularization regime.

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