The Argentine Electricity Sector

Electricity was first made available in Argentina in 1887 with the first public street lighting in Buenos Aires. The Argentine Government’s involvement in the electricity sector began in 1946 with the creation of the Dirección General de Centrales Eléctricas del Estado (General Directorate of Electric Power Plants of the State) to construct and operate electricity generation plants. In 1947, the Argentine Government created Agua y Energía Eléctrica S.A. (Water and Electricity, or ‘AyEE’) to develop a system of hydroelectric generation, transmission and distribution for Argentina.

In 1961, the Argentine Government granted a concession to the Compañía Italo Argentina de Electricidad (Italian Argentinean Electricity Company, or ‘CIADE’) for electrical distribution in a part of the City of Buenos Aires. In 1962, the Argentine Government granted a concession formerly held by the Compañía Argentina de Electricidad (Argentine Electricity Company, or ‘CADE’) to Servicios Eléctricos del Gran Buenos Aires (Electricity Services of Greater Buenos Aires, or ‘SEGBA’) for the generation and distribution of electricity to parts of Buenos Aires. In 1967, the Argentine Government granted a concession to Hidroeléctrica Norpatagónica S.A. (‘Hidronor’) to build and operate a series of hydroelectric generation facilities. In 1978, CIADE transferred all of its assets to the Argentine Government, following which CIADE’s business became state owned and operated.

By 1990, virtually all of the electricity supply in Argentina was controlled by the public sector (97% of total generation). The Argentine Government had assumed responsibility for the regulation of the industry at the national level and controlled all of the national electricity companies, AyEE, SEGBA and Hidronor. The Argentine Government also represented Argentine interests in generation facilities developed or operated jointly with Uruguay, Paraguay and Brazil. In addition, several provinces operated their own electricity companies. Inefficient management and inadequate capital spending, which prevailed under national and provincial government control, were in large measure responsible for the deterioration of physical equipment, decline in quality of service and proliferation of financial losses that occurred during this period.

In 1991, as part of the economic plan adopted by then President Carlos Menem, the Argentine Government undertook an extensive privatization program of all major state owned industries, including within the electricity generation, transmission and distribution sectors. In 1992, the Argentine Congress adopted Law No. 24,065, the Electricity Regulation Framework (a supplement to Law No. 15,336, Federal Electricity Law, and its Administrative Order No. 1,398/92), which was the keystone for the reform and privatization of the sector. The goal of the law was to modernize the electricity sector by promoting efficiency, competition, improved service and private investment.
It restructured and reorganized the sector, and provided for the privatization of virtually all business activities that had been carried out by Argentine state-owned enterprises. The law established the basis for the ENRE (Ente Nacional Regulador de la Electricidad or the ‘National Electricity Regulatory Entity’) and other institutional authorities in the sector, the administration of the Wholesale Electricity Market(‘WEM’), pricing at the spot, tariff-setting in regulated areas and for evaluating assets to be privatized. This law also had a profound, albeit indirect, impact at the provincial level, as virtually all of the provinces followed the regulatory and institutional guidelines of this law. Finally, this law, which continues to provide the framework for regulation of the electricity sector since the privatization of this sector, divided generation, transmission and distribution of electricity into separate businesses, each subject to segment-specific regulation.

Under Law No. 24,065, distribution and transmission activities are considered public services and defined as natural monopolies. These activities are completely regulated by the Government and require a concession. Although the concessions granted to distributors do not impose specific investment parameters, distributors are obligated to connect new customers and meet any increased demand. The expansion of existing transmission facilities by the respective concessionaires is not restricted. In contrast, generation, although regulated by the Government, is not deemed a monopoly activity and is subject to free competition by new market entrants. Operation of hydroelectric power plants requires a concession from the Government. New generation projects do not require concessions but must be registered with the Former Secretariat of Energy (‘SE’).

Many of the provincial governments, following the privatization path in the sector, have established their own politically and financially independent regulatory bodies at the provincial level. Local distribution in the provinces (except the City of Buenos Aires and certain areas of the Province of Buenos Aires that were served by SEGBA and today are served by Edenor and Edesur) is regulated by each province. Previously, the utilities themselves had played a major role in making sector policies and setting tariffs for the provinces.

At the end of 2001 and beginning of 2002, Argentina experienced an unprecedented crisis that virtually paralyzed the country’s economy through most of 2002 and led to radical changes in Government policies. The crisis and the Government’s policies during this period severely affected the electricity sector. Pursuant to the Emergency Law, the Argentine Government, among other measures:

• Converted electricity prices and transmission and distribution tariffs from their original U.S. Dollar values to Pesos at a rate of Ps. 1.00 per US$1.00;
• Froze all regulated transmission and distribution tariffs, revoked all price adjustment provisions and inflation indexation mechanisms in public utility concessions (including electricity transmission and distribution concessions), and empowered the Executive Branch to conduct a renegotiation of these concessions, including the tariffs for electricity transmission and distribution services; and
• Required that spot prices on the WEM be calculated based on the price of natural gas (which is also regulated by the Argentine Government), regardless of the fuel actually used in generation activities, even if gas is unavailable.

These measures created a huge structural deficit in the operation of the WEM and, combined with the devaluation of the Peso and high rates of inflation, had a severe effect on the electricity sector in Argentina, as electricity companies experienced a decline in revenues in real terms and a deterioration of their operating performance. Most electricity companies had also incurred large amounts of foreign currency indebtedness under the Convertibility regime. Following the elimination of the Convertibility regime and the resulting devaluation of the Peso, the debt service burden of these companies increased sharply, leading many of these companies to suspend payments on their foreign currency debt in 2002. This situation caused many Argentine electricity generators, transmission companies and distributors to defer further investments in their networks. As a result, Argentine electricity market participants, particularly generators, are currently operating at near full capacity, which could lead to insufficient supply to meet a growing national energy demand. In addition, the economic crisis and the resulting emergency measures had a material adverse effect on other energy sectors, including oil and gas companies, which has led to a significant reduction in natural gas supplies to generation companies that use this commodity in their generation activities.

In December 2004 the Argentine Government adopted new rules to meet demand growth, including the construction by the Argentine Government of two new 800 MW combined cycle generators. These generators commenced operations at full capacity in the first half of 2010. The costs of construction were primarily financed with net revenues of generators derived from energy sales in the spot market, deposited into a fund called the Fondo de Inversiones Necesarias que Permitan Incrementar la Oferta de Energía Eléctrica en el Mercado Eléctrico Mayorista (’FONINVEMEM’).

The construction of these new generators reflects a recent trend by the Argentine Government to take a more active role in promoting energy investments in Argentina. An example of this is the creation of Energía Argentina S.A. (‘ENARSA’) (Law No. 25,943), currently Integración Energética Argentina S.A. (‘IEASA’) with the purpose of developing almost every activity in the energy sector, from the exploration and exploitation of hydrocarbons, the transport and distribution of natural gas, to the generation, transmission and distribution of energy. In addition to these projects, in April 2006 the Argentine Congress enacted a law that authorized the Executive Branch to create a special fund to finance infrastructure improvements in the Argentine energy sector through the expansion of generation, distribution and transmission infrastructure relating to natural gas, propane and electricity. The special fund would obtain funds through cargos específicos (specific charges) passed on to customers as an itemization on their energy bills.

Finally, in September 2006 the Argentine Government, in an effort to respond to the sustained increase in energy demand following Argentina’s economic recovery after the crisis, adopted new measures that seek to ensure that energy available in the market is used primarily to service residential users and industrial and commercial users whose energy demand is at or below 300 kW and who do not have access to other viable energy alternatives. In addition, these measures seek to create incentives for generation plants to meet increasing energy needs by allowing them to sell new energy generation into the Energía Plus  system at unregulated market prices.

Continuing with the trend to encourage the installation of new generation, the SE by means of its Resolution No. 220/2007 and modifications thereto, allowed CAMMESA to execute WEM Supply Agreements with a generator agent of the WEM. The values to be paid by CAMMESA (Compañía Administradora del Mercado Eléctrico Mayorista or the ‘Argentine Wholesale Electricity Market Clearing Company’) in consideration for the capacity and the energy supplied by the generator must be approved by the SE. The generator shall guarantee certain availability of the generation units (established as a percentage), and if it fails to do so, penalties apply.

In 2008, the SE allowed CAMMESA to execute WEM Supply Agreements with generators the intention of which is to execute plans to repair and/or repower their generating equipment, and for the cost which would exceed 50% of the revenues that they expect to receive on the sales to the spot market.

In 2013, the SE introduced material changes to the structure and operation of the WEM through Resolution No. 95/2013, as amended, establishing a different remuneration scheme in Pesos (payable in cash and receivables) for the whole generation sector, except certain power plants and electricity sold under contracts with differential remuneration, regulated by SE.

Since November 2025, the SE introduced a new framework for the WEM’s progressive normalization, aimed at fostering greater competition among generators, encouraging direct contracting between demand and generators, and promoting a more decentralized fuel-supply scheme. The new framework introduces changes to the spot market and splits the forward market into two segments: energy and capacity. It also allocates part of the supply to seasonal procurement for distribution companies (Resolution No. 400/25).

Transactions among different participants in the electricity industry take place through the Wholesale Electricity Market, or WEM, which was organized concurrently with the privatization process as a competitive market in which generators, distributors and certain large users of electricity could buy and sell electricity at prices determined by supply and demand, and were allowed to enter into long-term electricity supply contracts. The WEM consists of:

• a term market where quantities, prices and contractual conditions are agreed upon directly between sellers and buyers. After the enactment of Resolution SE No. 95/2013 and MEyM No. 281/2017, this was limited to the Energy Plus and renewables market (MAT ER). Since the enactment of Resolution SE No. 400/2025, all power plants without contract (except for General San Martín and General Belgrano CCGTs (regulated by Resolution SE No. 59/23) and the national and binational hydroelectric plants Salto Grande and Yacyretá) can commercialize its power and energy in this market;
• a spot market where prices are established on an hourly basis as a function of the system’s demand; and
• a stabilized pricing system of spot prices, which we refer to as the seasonal price, set on a semi-annual basis and designed to mitigate the volatility of spot prices for purchases of electricity by distributors.

The following chart shows the relationships among the various actors in the WEM:

As of December 31, 2025, the maximum spot price of energy in the WEM amounted to AR$14,381 (Resolution SE No. 602/25). However, the following chart shows the monthly wholesale price that all electricity system users should pay to prevent the power grid from running into a deficit, as well as the seasonal energy price. The wholesale cost includes, in addition to the energy price, the power capacity payment, generation costs, fuels such as natural gas, Fuel Oil, Gas Oil, and mineral coal, and other minor items. As of December 2025, the coverage amounted to 78%.

Source: CAMMESA, converted into US$ at the official FX rate.

Thermal power generators

The remuneration consists of a fixed monthly charge for available capacity and a variable charge based on the energy generated, operated, and generated during peak-demand hours each month.

The price for generated energy at peak hours (between 6 and 11 pm) equals the price for the fuel type dispatched, applying a 2.0 factor in the summer (Dec-Feb) and winter (Jun-Aug) periods, and a 1.0 factor the rest of the year.

Combined Cycle GTs under Resolution SE No. 59/23

To promote the maintenance and efficient use of CCGT under legacy energy, in February 2023, the SE implemented an scheme under which generators commit to CAMMESA to maintain availability equal to 85% of net capacity, for a maximum of five years, in exchange for remuneration of US$2,000/MW-month, adjusted based on availability, as well as a partial payment of the power capacity price in AR$ under the legacy energy scheme.

The generated energy price was set at US$3.5/MWh for natural gas, US$6.1/MWh for FO or GO, and US$8.7/MWh for biofuel. The price for energy operated and generated at peak hours is set in AR$ according to the legacy energy price scheme.

On March 15, 2023, the SE established the implementation criteria, including: (i) CCGTs partially committed under other PPA could opt in, excluding self-generators with associated industrial or commercial demand; (ii) the term could not extend beyond May 31, 2028; and (iii) power generators could request termination by proving that the supplementary remuneration resulting from the legacy energy does not reflect cost variations. With the entry into force of the new framework for the normalization of the WEM, CCGTs that adhere to the scheme established by Resolution SE No. 400/25 are required to withdraw from the scheme set by Resolution SE No. 59/23.

In this context, Pampa kept CTLL and CTGEBA’s CCGTs (1,243 MW) and the two GTs at CTEB, making up the CCGT (569 MW) under the Res. SE No. 59/23 scheme through October 2025. As from November 2025, the obligations assumed under Resolution SE No. 59/23 remain suspended, provided that the conditions set by Resolution SE No. 400/25 remain in force and unchanged.

2024-2026 Contingency Plan

On October 1, 2024, the SE established a plan through Resolution No. 294/24 to address the energy grid’s critical condition in the months of greatest demand. The plan incorporates an opt-in 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:
• Additional fixed remuneration of US$2,000/MW-month for power, adjusted according to the criticality of the node where the unit is located and availability during peak demand hours, and 50% of this remuneration for power exceeding the committed power6.
• Additional variable remuneration in US$/MWh for energy generated during peak-demand periods, according to fuel, technology and criticality:

Note: A distinction is made between nodes with high (1.25), medium (1.00) and low (0.75) criticality, and summer and winter.

The SE may extend this additional remuneration for an additional 12 months, subject to the presentation of a maintenance program for each generating unit. In addition, CAMMESA must implement a strategic dispatch procedure to reduce supply restriction risks during periods of increased consumption, including dispatching reserves from units nearing the end of their useful life. Said maintenance programs were submitted and, on January 21, 2026, CAMMESA confirmed that the SE had approved the scheme’s extension for all units through March 31, 2027. Pampa adhered to this framework with the CPB, CTG, CTP, CTLL, CTGEBA and EcoEnergía power plants.

Unconventional source power generators

The remuneration for energy generated from unconventional sources was set at AR$32,718/MWh until October 2025, after they became subject to Resolution SE No. 400/25 regulatory framework.

Hydropower generators

Note: A factor of 1.05 is applied to capacity to compensate for the impact of scheduled maintenance, and a factor of 1.20 is applied to units responsible for the maintenance of control structures along the river course that are not associated with a power plant.

HPPL, Agua del Toro and Los Reyunos dams operated by HIDISA are remunerated under the 120 < MW ≤ 300 scale, while El Tigre dam operated by HIDISA is classified under the MW ≤ 50 scale. HINISA was remunerated under the 50 < MW ≤ 120 scale until October 2025, after which it became subject to SE Resolution No. 400/25.

The price for energy generated at peak hours (between 6 and 11 pm) equals the price with a 2.0 factor in the summer (Dec-Feb) and winter (Jun-Aug) periods, and a 1.0 factor the rest of the year.

New rules for the WEM normalization (Resolution SE No. 400/25)

Resolution SE No. 400/25 establishes that power generation not committed under PPAs nor allocated to meet seasonal demand of WEM distributors may be traded in the spot market. The new regulatory framework preserves existing PPAs, whose output remains allocated to cover distributors’ seasonal demand until their expiration. Once those terms conclude, generators may choose to participate in the spot market or sign contracts with distributors or large users.

This scheme benefits the most efficient, well-located thermal units with fuel self-procurement, which can achieve higher profit margins, fully correlated to US$. In this context, Pampa operates three strategically located CCGTs: CTLL in Vaca Muerta; CTGEBA at the system’s zero node; and CTEB, which uses natural gas and GO, in which Pampa holds a 50% equity stake. Regarding open cycles, Pampa operates CPB (which consumes fuel oil), CTG and CTP. Regarding hydroelectric, the only plant covered by this regime is HINISA, due to its provincial status, until its concession expires in July 2026.

Variable remuneration

In the spot market, energy dispatch is based on a marginal pricing scheme. Energy remuneration is equal to the Variable Production Cost (CVP) declared by the dispatched unit, plus an Adapted Marginal Rent (RMA), calculated as (CMgh × FP – CVP) × FRA, where CMgh is the system hourly marginal cost, FP is the loss factor of the relevant node, and FRA is the adapted rent factor.

For thermal generation, the RMA is capped by the FRA, which determines the proportion of rent captured by the generator: (i) FRA = 1 for generation commissioned after January 1, 2025, capturing the full rent; (ii) generation with fuel self-procurement has FRA = 15% as from 2025, 25% in 2027, and 35% as from 2028; (iii) generation supplied with gas by CAMMESA has FRA = 12% as from 2025, 15% in 2027, and 17.5% as from 2028; and (iv) units without fuel management do not capture rent (FRA = 0), with CVP equivalent to reference values established by CAMMESA. In addition, a minimum rent is established for thermal generation at US$2/MWh when the declared CVP is below US$60/MWh, and at US$7/MWh when the declared CVP is equal to or above US$60/MWh. Thermal units dispatched for operational reasons or due to local constraints receive only their declared CVP. If committed volumes are not complied with, a 70% penalty of the declared value applies, with exceptions for deviations of up to 20% or duly justified situations.

For hydroelectric, renewable and self‑generation, the same marginal pricing scheme applies, assuming CVP = 0. Units commissioned before January 1, 2025, have an FRA = 15% as from 2025, 25% in 2027, and 35% as from 2028, with a minimum RMA of US$22/MWh for hydroelectric generation and US$32/MWh for renewables and self‑generators. Plants commissioned as of January 1, 2025, have FRA = 1, with no upper or lower limits.

Capacity remuneration

Capacity in the spot market is remunerated through an Available Capacity (PPAD) payment of US$12/MWh, recognizing 90 hours per week and weighting by technology and fuel type: (i) if exclusively fueled by natural gas, 1.1 in summer/winter and 0.9 for the rest of the year; (ii) if using alternative fuels, 1.5 in summer/winter and 1.0 for the rest of the year; (iii) 0.5 for hydroelectric plants; and (iv) no capacity remuneration is recognized for renewables. For thermal plants without fuel self-procurement or supplied by CAMMESA, 100% of capacity is remunerated while dispatched and 80% when not dispatched until December 2026, 40% during 2027, and 0% as from 2028. Additionally, US$1,000 per MW‑month is recognized as a base reliability reserve, regardless of the fuel used or the supply modality.

Remuneration scheme for generation not subject to Resolution SE No. 400/25

The SE established that units not committed to capacity or energy availability contracts in the WEM, nor authorized to participate in the spot market under Resolution SE No. 400/25 shall remain subject to the remuneration scheme set in Resolution SE No. 483/25 and its complementary or amending regulations. This includes General San Martín and General Belgrano CCGTs (regulated by Resolution SE No. 59/23) and the national and binational hydroelectric plants Salto Grande and Yacyretá. For Pampa, this scheme applies to HIDISA and HPPL.

In addition, capacity remuneration is calculated based on Monthly Real Capacity Availability (DRP) and the technology‑specific guaranteed price, eliminating the base provision. For hydroelectric, availability is determined independently of reservoir levels, and for pumped‑storage, both turbine operation and pumping availability are considered. The scheme was simplified by reducing distinctions by technology and scale in capacity and energy prices.

Monthly remuneration recognizes both available capacity and energy, the latter being the sum of generated energy, operated energy, and energy generated during peak hours. Capacity payments are determined based on each unit’s average monthly DRP and the Guaranteed Capacity Price, according to its technology and scale.

In September 2006, to encourage the development of new generation supply, the SE implemented the Energía Plus program, which allows generators to sell energy to GU300 above their 2005 electricity consumption under freely negotiated US$ prices, provided they have fuel supply and transportation. If they cannot meet the demand, the generator must buy the energy on the spot market. GU300 not contracting in the MAT must pay the Surplus Demand Incremental Average Charge (Cargo Medio Incremental de la Demanda Excedente, CMIEE) set as the maximum between AR$1,200/MWh and the temporary dispatch surcharge since June 2018 (SE Note No. 28663845/18). Some Energía Plus contracts are adjusted according to CAMMESA price variations. From January 2021, with the implementation of Plan Gas, Pampa assigns gas supply and transportation to CAMMESA. Currently, CTG, EcoEnergía and CTGEBA provide Energía Plus to different WEM customers with a 283 MW total gross capacity.

However, on January 28, 2025, the SE introduced changes to dispatch regulations and WEM operations, which impacted Energía Plus, limiting the renewal and execution of new contracts until October 31, 2025. As of that date, generators are required to dispatch their capacity and energy to the spot market or the MAT (Resolution SE No. 400/25).

To increase generation supply, the SE passed Resolution No. 220/07 empowering CAMMESA to enter into WEM long-term PPAs for the energy produced with new generation equipment. These are long-term PPAs denominated in US$, and the price payable by CAMMESA remunerates the investment made by the plant at a rate of return accepted by the SE. CTLL’s TG04 (79 MW) and CTEB’s expansion (279 MW) are remunerated under this scheme until July 2026 and February 2033, respectively.

The power generators awarded under the SEE’s March 2016 tenders entered into a PPA for a fixed price (US$/MW-month) and a variable price excluding fuel (US$/MWh), with CAMMESA as offtake on behalf of distributors and WEM GU. The units remunerated under this regulation are CTLL’s GT05 (105 MW) and CTPP (100 MW) until August 2027 and CTIW (100 MW) until December 2027.

In May 2017, the SEE launched a call for tenders for co-generation and conversion of existing equipment to CCGT. Awarded projects executed a 15-year PPA for an available power capacity price plus the non-fuel CVP for the delivered energy and the fuel cost (if tendered).

CTGEBA holds a PPA for 400 MW through July 2035, which includes fuel supply. Since the entry into force of Plan Gas in January 2021, CTGEBA had operationally assigned gas supply and transportation to CAMMESA, which established centralized dispatch. With the new WEM guidelines (Resolution SE No. 400/25) and the assignment of Plan Gas contracts (Resolution SE No. 501/25), Pampa discontinued such assignment as of December 2025, and CAMMESA assumed fuel management for this PPA.

In October 2015, Law No. 27,191 was enacted, requiring that by December 31, 2025, 20% of Argentina’s total energy demand be covered by renewable energy sources. To meet this objective, large users at WEM and CAMMESA should cover the specified percentage of their demand from such sources by December 31, 2025. Several incentives were established, including tax benefits and the creation of the Fund for the Development of Renewable Energy (Fondo para el Desarrollo de Energía Renovables, FODER) for financing projects. As of year-end, 19% of energy demand was met by renewable sources, and Law No. 27,191 was not renewed.

RenovAr

Under Law No. 27,191, in 2016, the RenovAr Program’s rounds 1 and 1.5 were launched (Resolution MEyM No. 71/16 and 252/16), awarding 1,142 MW under round 1, and 1,281.5 MW under round 1.5. In 2017, round 2 was called, and 2,043 MW were awarded (Resolution MEyM No. 275/17). Finally, in 2018, 246 MW were awarded under round 3 (MiniRen). All greenhouse gas reductions resulting from projects under RenovAr or any other renewable power project, as per Law No. 27,191, should be accounted for by the Federal Government towards its contribution target under its international climate commitments. PEA (100 MW) is remunerated under the RenovAr round 1 until March 2040.

MAT ER

Created in August 2017, this regime allows large users at both the WEM and the distribution network to purchase or self-generate clean energy to meet their electricity demand through renewable sources. Under this scheme, PEPE 2, 3, 4 and 6 sell energy under US$-denominated PPAs to private customers for 327 MW, with an average term of approximately 3.5 years. Besides, Pampa has sold third parties’ renewable energy since 2019, with a total 5 GWh volume in 2025, contributing to increasing the MAT ER segment’s margin. Generation surpluses contracted in the MAT ER are remunerated at the minimum price effective for each technology under RenovAr for up to 10% of the power generation. The remainder is sold on the spot market regarding Res. SE No. 400/25.