The Argentine Electricity Sector

El Sector Eléctrico de Argentina

History and Evolution of the 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 (Energy 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.

Since 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.

Current Situation of the Sector

For generation not covered by contracts, through Resolutions No. 19E/2017 of the SEE (Secretariat of Electric Energy) and 1/2019 of the SRRYME (Secretariat of Renewable Resources and Electricity Market), from February 1, 2017 to January 31, 2020, a US$-denominated remuneration scheme was stablished, which provided for a remuneration for power capacity and non-fuel energy, as well as the elimination of remunerations in the form of receivables. It is worth mentioning that as from March 1, 2019, reductions were applied to remuneration, and a reduction coefficient was incorporated to the power capacity remuneration, according to the unit’s utilization factor of the unit.

Later, Resolution No. 31/2020 of the SE (Secretariat of Energy), converted the entire remuneration scheme to the local currency at a FX (Foreign Exchange) of AR$60/US$ with lower power capacity remuneration, effective as from February 1, 2020. An additional remuneration was incorporated in the hours of high thermal dispatch and an update factor was established as from the second month of its application, which follows a formula consisting of 60% CPI (Consumer Price Index) and 40% IPIM (Wholesale Domestic Price Index). However, the SE, through the Note NO-2020-24910606-APN-SE#MDP, instructed CAMMESA (Compañía Administradora del Mercado Mayorista Eléctrico or the Argentine Wholesale Electricity Market Clearing Company) to postpone until further decision the application of said update factor.

Regarding the fuel supply for power plants, the purchase and dispatch of fuels remained centralized in CAMMESA until October 2018, excluding generators with Energía Plus contracts. In November 2018, Resolution No. 70/2018 of the SGE (former Government Secretariat of Energy) amended SE Resolution No. 95/2013, authorizing power generators, co-generators and self-generators within the WEM (Wholesale Electricity Market) to acquire fuels of any kind required for own power generation, originally for units with remuneration scheme under SEE Res. No. 19E/2017, and later being extended to units with differential remuneration. The cost of generation with own fuels would be valued according to the mechanism for the recognition of CVP (Variable Production Cost) standardized by CAMMESA. It should be noted that for agents which ‘did not or couldn’t’ make use of such capacity, CAMMESA continued being in charge of the commercial management and the dispatch of fuels. However, through Resolution No. 12/19 of the MDP (Ministry of Productive Development), as from December 30, 2019, SGE Resolution No. 70/18 was abrogated and the centralization of fuel procurement and supply in CAMMESA was restored, a measure that does not cover generators with Energía Plus contracts.

On the other hand, as a result of the state emergency in the national electricity sector, on March 22, 2016 the SEE through Resolution No. 21/16 launched a call for tenders for 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. Moreover, in line with the measures seeking to increase the electric power generation offer, on May 10, 2017 the SEE issued Resolution No. 287/17 launching a call for tenders for co-generation projects and the closing to combined cycles over existing equipment.

Regarding renewable energies, in October 2015, Law No. 27,191 (regulated by Executive Order No. 531/16) was passed, which amends Law No. 26,190 on the promotion of renewable sources of energy. Among other measures, it provided that by December 31, 2025, 20% of the total demand of energy in Argentina should be covered with renewable sources of energy.

  • MEyM (former Ministry of Energy and Mining) Resolution No. 71/16, launched the RenovAr 1 open call for tenders, continuing with RenovAr 1.5 (MEyM Resolution No. 252-E/16), RenovAr 2.0 (MEyM Resolution No. 275-E17) and MiniRen Round 3 (SGE Resolution No. 100/18)
  • MEyM Resolution No. 281-E/2017 issued in August 2017, regulated the MAT ER (Term Market from Renewable Energy Sources) regime, which aims to set the conditions for large users within the WEM and GUDI (Large Distribution Company Users) to meet their demand supply obligation from renewable sources through the individual purchase within the MAT ER or through self-generation from renewable sources
  • Finally, on December 27, 2017, Law No. 27,424 was published, which declares it of national interest the distributed generation of electric power from renewable sources destined to self-consumption and the possible injection of surpluses into the distribution network
The Wholesale Electricity Market (‘WEM’)

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 former Secretariat of Energy (‘SE’) Resolution No. 95/2013, this was limited to the Energy Plus market, and later being added the Term Market from Renewable Energy Sources, also known as MAT ER, according to Resolution No. 281/2017 of former Ministry of Energy and Mining);
  • a spot market where prices are established on an hourly basis as a function of economic production cost; 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:

Key Participants

CAMMESA

The creation of the WEM (‘Wholesale Electricity Market’) made it necessary to create an entity in charge of the management of the WEM and the dispatch of electricity into the SADI (Sistema Argentino de Interconexión or ‘Argentine Electricity Grid’). The duties were entrusted to CAMMESA (Compañía Administradora del Mercado Eléctrico Mayorista or ‘Argentine Wholesale Electricity Market Clearing Company’), a private company created for this purpose.

CAMMESA is in charge of:

  • the dispatch of electricity into the SADI, maximizing the SADI’s safety and the quality of electricity supplied and minimizing wholesale prices in the spot market;
  • planning energy capacity needs and optimizing energy use in accordance with the rules set forth from time to time by the Former Secretariat of Energy (‘SE’);
  • monitoring the operation of the term market and administering the technical dispatch of electricity under agreements entered into in that market;
  • acting as agent of the various WEM agents and carrying out the duties entrusted to it in connection with the electricity industry, including billing and collecting payments for transactions between WEM agents (upon enactment of SE Resolution No. 95/2013, this was limited to the contracts then in force and, thereafter, to those contracts executed under Energy Plus Program, and later being added those contracts executed under Term Market from Renewable Energy Sources (‘MAT ER’) according to Resolution No. 281/2017 of former Ministry of Energy and Mining);
  • purchasing and/or selling electric power from abroad or to other countries by performing the relevant import/export transactions;
  • purchasing and administrating of fuels for the applicable WEM generators; and
  • providing consulting and other related services.

Five groups of entities each hold 20% of the capital stock of CAMMESA. The five groups are the Argentine Government, the associations that represent the generation companies, transmission companies, distribution companies and large users.

CAMMESA is managed by a board formed by representatives of its shareholders. The board of CAMMESA is composed of ten regular and ten alternate directors. Each of the associations that represent generation companies, transmission companies, distribution companies and large users are entitled to appoint two regular and two alternate directors of CAMMESA. The other directors of CAMMESA are the Under Secretariat of Electric Energy, who is the board chairman in virtue of the delegation of the Federal Government, and an independent member, who acts as vice chairman. The decisions adopted by the board of directors require the affirmative vote of the board chairman. CAMMESA’s operating costs are financed through mandatory contributions by the WEM agents.

 

Generators

Generators are companies with electricity generating plants that sell output either partially or wholly through the SADI. Generators are subjected to the scheduling and dispatch rules set out in the regulations and managed by CAMMESA. Privately owned generators may also enter into direct contracts with distributors or large users. However this possibility was suspended by SE Resolution No. 95/2013, limited to the contracts executed under Energy Plus Program, and later being added those contracts executed under MAT ER according to Resolution No. 281/2017 of former Ministry of Energy and Mining.

As of December 31, 2019, Argentina had a nominal installed capacity as reported by CAMMESA of approximately 39,704 MW (+1,166 MW compared to 2018), composed by 61.8% of thermal, 27.2% of hydroelectric, 6.5% of renewable and 4.4% of nuclear. This increase was mainly due to the commissioning of renewable units under the RenovAr and MAT ER programs for 1,120 MW, including PEPE II and PEPE III (106 MW). In the thermal area, 503 MW were commissioned, mainly under former Ministry of Energy and Mining (MEyM) Res. No. 287/17, including the first phase of Genelba Plus’ expansion project (207 MW)(1).

Moreover, during 2019 there was a 5% decrease in power generation, with volumes of 130,838 GWh and 137,199 GWh, for the years 2019 and 2018, respectively, mainly due to the economic downturn.

  • Thermal power generation remained as the main resource to meet the electricity demand, fired with natural gas or liquid fuels (gas oil (GO) and fuel oil (FO)) and mineral coal, supplying an electricity volume of 80,138 GWh (61%), followed by hydroelectric power generation, which contributed 34,961 GWh net of pumping (27%), nuclear power generation, with 7,927 GWh (6%), and renewable power generation with 7,812 GWh (6%). Additionally, there were imports for 2,746 GWh (higher than the 344 GWh recorded in 2018), exports for 261 GWh (7% lower than in 2018), and losses for 4,443 GWh (4% higher than in 2018).
  • Hydroelectric power generation net of pumping and thermal power generation’s contribution volumes experienced a 12% and 9% year-on-year decrease, respectively, mainly as a result of the lower electricity demand and the entrance of renewable energies. These increases were partially offset by a 23% and 133% year-on-year increase in nuclear and renewable generation, respectively, mainly as a result of the commissioning under the RenovAr and MAT ER (Term Market from Renewable Energy Sources) programs, and the commissioning of Central Nuclear Embalse’s reconditioning.

Note: (1) The second phase of this project was commissioned on July 2, 2020, completing the expansion for a total 400 MW.

The following chart shows the evolution of power generation by source (thermal, hydroelectric, nuclear, and renewable) in GWh:

Type of Generation 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Thermal 66,465 73,573 82,495 82,953 83,048 86,340 90,099 88,530 87,727 80,138
Hydroelectric 39,672 38,773 35,903 39,830 40,175 39,262 35,727 39,183 39,669 34,961
Nuclear 6,692 5,892 5,904 5,732 5,258 6,519 7,677 5,716 6,453 7,927
Renewable 16 356 462 849 2,504 2,632 2,635 3,350 7,812
Total Generation in Argentina 112,829 118,254 124,659 128,978 129,330 134,624 136,135 136,064 137,199 130,838

 

Transmission Companies

Transmission companies hold a concession to transmit electric energy from the bulk supply point to electricity distributors. The transmission activity in Argentina is subdivided into two systems: the High Voltage Transmission System (‘STEEAT’), which operates at 500 kV and transports electricity between regions, and the regional distribution system (‘STEEDT’) which operates at 132/220 kV and connects generators, distributors and large users within the same region. Transener is the only company in charge of the STEEAT, and six regional companies are located within the STEEDT (Litsa, Transnoa, Transnea, Transpa, Transba and Distrocuyo). In addition to these companies, there are also independent transmission companies that operate under a technical license provided by the STEEAT or STEEDT companies.

Transmission and distribution services are carried out through concessions. These concessions are re-distributed periodically based on a re-bidding process. Transmission companies are responsible for the operation and maintenance of their networks, but not for the expansion of the system. The transmission concessions operate under the technical, safety and reliability standards established by the ENRE (Ente Nacional Regulador de la Electricidad or ‘National Electricity Regulatory Entity’). Penalties are applied whenever a transmission concessionaire fails to meet these criteria, particularly those regarding outages and grid downtime. Generators can only build lines to connect to the grid, or directly to customers. Users pay for new transmission capacity undertaken by them or on their behalf. A public hearing process for these projects is conducted by the ENRE, which issues a ‘Certificate of Public Convenience and Necessity’. Transmission or distribution networks connected to an integrated system must provide open access to third parties under a regulated toll system unless there is a capacity constraint.

 

Distribution Companies

Distributors are companies holding a concession to distribute electricity to consumers. Distributors are required to supply any and all demand of electricity in their exclusive areas of concession, at prices (tariffs) and conditions set in regulation. Penalties for non-supply are included in the concessions agreements. The three distribution companies divested from SEGBA (Edenor, Edesur and Edelap) represent more than 40% of the electricity market in Argentina. Only a few distribution companies (i.e., Empresa Provincial de Energía de Córdoba, Empresa de Energía de Santa Fé, and Energía de Misiones) remain in the hands of the provincial governments and cooperatives. Edelap has been transferred to the jurisdiction of the Province of Buenos Aires. Moreover, in March 2019, the Federal Government executed an agreement with the province of Buenos Aires and the Autonomous City of Buenos Aires for the transfer of Edenor and Edesur, still pending of completion.

Each distributor supplies electricity and operates the electricity distribution network in a specific geographical area under a concession. Each concession determines, among others, the concession area, the quality of service required, the tariffs to be paid by consumers, and the extent of the obligation to meet the demand.

The ENRE monitors the compliance of the distributors at the federal level, and provides a mechanism for public hearings in which complaints against distributors can be heard and resolved. In addition, the provincial regulatory bodies control the compliance of the local distributors with their respective concessions and local regulatory frameworks.

The provincial authorities and the ENRE control the fulfillment of the concession agreements of these public services in the provinces. Many provincial governments that have launched reforms in the electricity sector have followed the terms and conditions of the concessions used for the distribution of public services at the national level.

 

Large users

The wholesale electricity market classifies large users of energy into three categories: (1) Grandes Usuarios Mayores (Major Large Users or ‘GUMAs’), (2) Grandes Usuarios Menores (Minor Large Users or ‘GUMEs’) and (3) Grandes Usuarios Particulares (Particular Large Users or ‘GUPAs’).

Each of these categories of users has different requirements with respect to purchases of their energy demand. For example, GUMAs are required to purchase 50% of their demand through supply contracts and the remainder in the spot market, while GUMEs and GUPAs are required to purchase all of their demand through supply contracts.

Large users participate in CAMMESA by appointing two acting and two alternate directors through the Asociación de Grandes Usuarios de Energía Eléctrica de la República Argentina (‘Argentine Association of Electric Power Large Users’ or AGUEERA).

Generation Dispatch and Fuels

Price of Electricity

The energy authority has continued with the policy launched in the year 2003 whereby the WEM (Wholesale Electricity Market) spot price is determined according to the available power generating units’ CVP (Costo Variable de Producción or Variable Production Cost) with natural gas, even if these units are not generating electricity with such fuel (Resolution No. 240/03 of the SE (former Secretariat of Energy)). The additional cost for the consumption of liquid fuels is recognized outside the specified market price as a temporary dispatch surcharge. Furthermore, pursuant to Resolution No. 25/18 of the SGE (former Government Secretariat of Energy), the WEM bears the costs of imported gas as from October 1, 2018.

As regards the remuneration for legacy generation capacity, the remuneration scheme established by the Resolution No. 19/17 of the SEE (Secretariat of Electric Energy) remained in force until February 28, 2019, from March 1, 2019 to January 31, 2020 the Resolution No. 1/19 of the SRRYME (Secretariat of Renewable Resources and Electricity Market) was in effect, and, as from February 1, 2020, SE Res. No. 31/20 is in effect.

Until October 2019, the approved average monthly spot price for energy was AR$480/MWh, which is the maximum price stipulated pursuant to SEE Provision No. 97/18. As from November 2019, this price increased to AR$720/MWh pursuant to SEE Provision No. 38/19.

On the other hand, the following chart shows the average monthly price that all electricity system users should pay so that the power grid would not run into a deficit. This cost includes not only the energy price, but also the power capacity fee, the generation cost, fuels such as natural gas, fuel oil or gas oil, and other minor items.

 

Note: Average monthly monomic price in US$/MWh. Source: CAMMESA.

 

Fuel Supply

Regarding fuel supply for power generation, during 2019 SGE Resolution No. 70/18 issued in November 2018 remained in force, which empowered thermal plants to self-procure fuel for power generation. For those not exercising such option, CAMMESA (Compañía Administradora del Mercado Mayorista Eléctrico or the Argentine Wholesale Electricity Market Clearing Company) remained in charge of the fuel’s operating and commercial management. For its instrumentation, maximum prices of natural gas within the PIST (Transportation System Entry Point) for power plants to be traded within the WEM, established by Resolution No. 46/18 of the MinEn (former Ministry of Energy) and SGE Notes No. 66680075/18 and 07973690/19, were observed.

Moreover, in case the generator has opted to supply its own fuel for generation and such fuel is not available at the time of dispatch, the calculation of the power capacity availability is reduced to 50% of its actual availability. Similarly, it loses its dispatch order, and in case the OED (Agency in Charge of Dispatch or Organismo Encargado del Despacho) assigns it fuel for generation, only the Generated Energy will be remunerated at 50% of the approved non-fuel variable costs.

However, pursuant to Resolution No. 12/19 of the MDP (Ministry of Productive Development), fuel supply was again centralized in CAMMESA as from December 30, 2019 (except for fuel supply for generators under Energía Plus).

As regards fuel consumption, in 2019 the country continued purchasing LNG (liquefied natural gas) and its re-gasification, as well as natural gas from the Republic of Bolivia. However, the natural gas supply remained insufficient to meet power generation needs and, therefore, liquid fuels (fuel oil and gas oil) continued to be resorted to in order to meet the demand, although in volumes significantly lower than in 2018.

Natural gas consumption for power generation recorded a 5% decrease in 2019 compared to the previous year (17.2 million dam3 (cubic decameters)). Fuel oil consumption was 67% lower than in 2018, totaling 0.2 million ton. Moreover, gas oil and mineral coal consumption also experienced a 54% and 66% decrease, respectively, compared to 2018.

 

legacy

Resolución SEE N° 19/17: Febrero 2017 – Febrero 2019

Resolution No. 19/17 of the SEE (Secretariat of Electric Energy), issued on February 2, 2017, established a remuneration scheme for legacy capacity which was applied from January 1 to February 28, 2019, when it was amended by Resolution No. 1/19 of the SRRYME (Secretariat of Renewable Resources and Electricity Market), which entered into effect on March 1, 2019.

Resolution No. 19/17 provided for remunerative items based on technology and scale, establishing US$-denominated prices payable in AR$ by applying BCRA (Central Bank of the Republic of Argentina)’s FX (foreign exchange) effective on the last business day of the month of the transaction’s maturity date, according to CAMMESA (Compañía Administradora del Mercado Mayorista Eléctrico or the Argentine Wholesale Electricity Market Clearing Company)’s Procedures.

 

Thermal Power Generators

Resolution No. 19/17 defined a remuneration for power capacity based on technology and scale collectable by agents with DIGO (Guaranteed Availability Commitments) declaration for the power capacity and energy from their units not covered by PPAs (Power Purchase Agreements) with a differentiated remuneration regime. The DIGO should be declared for each unit and for a term of three years, together with information for the Summer Seasonal Programming, with the possibility to later amend availability values, on a semiannual basis. Generators may enter into a DIGO agreement with CAMMESA, which may assign it to the demand. The capacity remuneration for thermal generators with DIGO will be proportional to their compliance. The base remuneration amounted to US$7,000/MW-month, applicable to generators with DIGO. The additional remuneration for additional available power capacity amounted to US$2,000/MW-month, seeking to encourage DIGO for the periods with a higher demand. Bimonthly, CAMMESA should define a Monthly Thermal Generation Goal for the set of qualified generators and call for additional power capacity availability offers with prices not exceeding the additional price.

For those not offering DIGO, the power capacity remuneration was set at the minimum value.

Technology / Scale Minimum Price
(US$ / MW-month)
Large CC (Combined Cycle) Capacity > 150 MW 3,050
Large ST (Steam Turbine) Capacity > 100 MW 4,350
Small ST Capacity ≤ 100 MW, Internal Combustion Engines 5,700
Large GT (Gas Turbine) Capacity > 50 MW 3,550

 

Regardless of the thermal unit, the remuneration for generated energy was US$5/MWh if fired with natural gas, and US$8/MWh if fired with liquid fuels, except for internal combustion engines, which prices amounted to US$7/MWh and US$10/MWh for gas or liquid fuels consumptions, respectively. The remuneration for operated energy was applied to the integration of hourly power capacities for the period (over rotating units) at a price of US$2/MWh for any type of fuel.

Moreover, for low-use thermal generators or generators having frequent startups, an additional remuneration was established based on the monthly generated energy at a price of US$2.6/MWh multiplied by the usage/startup factor. The usage factor was set based on the rated power’s Utilization Factor recorded during the last rolling year, with a 0.5 value for thermal units with a factor lower than 30% and a 1.0 value for units with a factor lower than 15%. In all other cases, the factor equals 0. The startup factor, which was set based on startups recorded during the last rolling year for issues associated with the economic dispatch made by CAMMESA, was as follows: i) 0 for units with 74 or fewer startups; ii) 0.1 for units recording between 75 and 149 startups; and iii) 0.2 for units recording more than 150 startups.

 

Hydro Power Generators

In the case of CHs (Hydroelectric Power Plants), a base remuneration for capacity (determined by the actual power capacity plus that under programmed and/or agreed maintenance) and an additional remuneration for capacity (applicable to power plants of any scale for their actual availability, based on the applicable period) were established. Availability is determined independently of the reservoir level, the contributions made, or the expenses incurred.

Furthermore, in the case of pumping hydroelectric power plants, the following is taken into consideration to calculate availability: i) the operation as turbine at all hours within the period, and ii) the availability as pump at off-peak hours every day and on non-business days. In the case of CHs 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.

Classification Base Price
(US$ / MW-month)
Medium HI (Hydroelectric Plants) Capacity > 120 ≤ 300 MW 3,000
Small HI Capacity > 50 ≤ 120 MW 4,500
Medium Pumped HI Capacity > 120 ≤ 300 MW 2,000
Renewable HI Capacity ≤ 50 MW 8,000

 

Type of Power Plant Additional Price
(US$ / MW-month)
Conventional 1,000
Pumped 500

 

The allocation and collection of 50% of the additional remuneration was conditional upon the generator taking out insurance on critical equipment, as well as updating of the plant’s control systems pursuant to an investment plan to be submitted based on criteria to be defined by the SGE (former Government Secretariat of Energy).

For hydroelectric generation, independently of the scale, the prices for generated energy amounted to US$3.5/MWh, added to the price for operated energy, which amounted to US$1.4/MWh.

 

Other Considerations

The remuneration for wind power was composed by a base price of US$7.5/MWh and an additional price of US$17.5/MWh, which were associated with the availability of the installed equipment, with an operating permanence longer than 12 months as from the beginning of the summer seasonal programming.

Furthermore, SEE Resolution No. 19/17 abrogated the Overhauls Remuneration set by Resolution No. 95/13 of the SE (former Secretariat of Energy) and provided that, as regards the repayment of loans, already accrued and/or committed credits should be applied first, being the balance repaid discounting US$1/MWh from the generated energy until the total cancellation of the financing.

SRRYME Resolution No. 1/19: March 2019 – February 2020

On March 1, 2019, Resolution No. 1/19 of the SRRYME (Secretariat of Renewable Resources and Electricity Market) was published, which modified certain aspects of the remuneration scheme previously defined by Resolution No. 19/17 of the SEE (Secretariat of Electric Energy).

 

Thermal Power Generators

For generators without a DIGO (Guaranteed Availability Commitments) declaration, the following table of base prices for power capacity was applied:

Technology / Scale Capacity’s Base Price
(US$ / MW-month)
Large CC (Combined Cycle) Capacity > 150 MW 3,050
Small CC Capacity ≤ 150 MW 3,400
Large ST (Steam Turbine) Capacity > 100 MW 4,350
Small ST Capacity ≤ 100 MW, Internal Combustion Engines 5,200
Large GT (Gas Turbine) Capacity > 50 MW 3,550
Small GT Capacity ≤ 50 MW 4,600

 

Furthermore, a DIGO offer scheme was established for quarterly periods: a) summer (December through February); b) winter (June through August), and c) ‘other’, which comprises two quarters (March through May, and September through November). For agents with a DIGO declaration, the guaranteed capacity price was applied, which equaled US$7,000/MW-month in the summer and winter quarters, but US$5,500/MW-month in the ‘other’ quarters.

Additionally, the capacity remuneration ―whether or not the agent had a DIGO declaration― was weighted by a load factor equivalent to the average dispatch factor for the generating unit during the rolling year prior to the calculation month, and applied a coefficient to the power capacity remuneration if the load factor was: i) higher than 70%, 100% of the power capacity remuneration was paid; ii) lower than 30%, 70% of the power capacity remuneration was paid; and iii) between 30% and 70%, the power capacity remuneration was linearly associated with between 70% and 100% of the power capacity remuneration.

Generated energy remuneration values were reduced by US$1/MWh for all technologies except for internal combustion engines, where the reduction was of US$3/MWh. The remuneration value for operated energy was reduced from US$2/MWh to US$1.4/MWh.

Finally, the additional remuneration schemes were abrogated: capacity remuneration to encourage DIGO during peak demand period, variable remuneration for efficiency, and power capacity remuneration for low-use thermal generators.

 

Hydro Power Generators

SRRYME Resolution No. 1/19 maintained the base prices for power capacity established by SEE Resolution No. 19/17, as well as remuneration values for generated and operated energy. However, as regards the power capacity payment, the hours during which a hydroelectric generator was not available due to programmed and agreed maintenance were no longer computed for the calculation of the power capacity remuneration. However, in order to mitigate this impact, in May 2019 Note No. 46631495 of the SME (Subsecretariat of Electricity Market) provided for the application of a 1.05 factor on the capacity payment.

 

Other Considerations

For generation from unconventional sources, a single remuneration value for generated energy was established at US$28/MWh, or 50% of this value if it is generated prior to commercial commissioning.

As regards the refund of the amount disbursed to generators under the loan agreements for the execution of overhauls in their units, the application of all receivables accrued in favor of generators for settlement was established, as well as a discount scheme in the generator’s revenues equivalent to the maximum between US$1/generated MWh or US$700/MW-month for the unit’s real availability.

SE Resolution No. 31/20: Current Spot Remuneration Scheme

On February 27, 2020, Resolution No. 31/20 of the SE (Secretariat of Energy) was published in the Public Gazette, which modified certain aspects of the remuneration scheme set forth by Resolution No. 1/19 of the SRRYME (Secretariat of Renewable Resources and Electricity Market), effective as from February 1, 2020. The new Resolution converts the entire remuneration scheme to the local currency at a FX (exchange rate) of AR$60/US$ and establishes an update factor as from the second month of its application, which follows a formula consisting of 60% CPI (Consumer Price Index) and 40% IPIM (Wholesale Domestic Price Index).

 

Thermal Power Generators

SE Resolution No. 31/20 reduces the power capacity remuneration, whether base or guaranteed, depending on the technology used. However, for CTs (Thermal Power Plants) with a total installed power capacity lower than or equal to 42 MW, the base power capacity values set out by SRRYME Resolution No. 1/19 remain in effect.

Technology / Scale Capacity
Base Price
(AR$/MW-month)
Variation vs.
SRRYME Resolution
No. 1/19*
Large CC (Combined Cycle) Capacity > 150 MW 100,650 -45%
Small CC Capacity ≤ 150 MW 112,200 -45%
Large ST (Steam Turbine) Capacity > 100 MW 143,550 -45%
Small ST Capacity ≤ 100 MW,
Internal Combustion Engines Capacity > 42 MW
171,600 -45%
Large GT (Gas Turbine) Capacity > 50 MW 117,150 -45%
Small GT Capacity ≤ 50 MW 151,800 -45%
Small CC Capacity ≤ 15MW 204,000
Small ST Capacity ≤ 15MW 312,000
Small GT Capacity ≤ 15MW 276,000
Internal Combustion Engines Capacity ≤ 42 MW 312,000

Note: * It assumes a FX of AR$60/US$.

 

As regards the remuneration for the offered guaranteed power capacity, the following scheme remains in effect:

Period Capacity Base Price
(AR$/MW-month)
Variation vs. SRRYME Resolution
No. 1/19*
Summer (December – February) and Winter (June – August) 360,000 -14%
Other (March – May and September – November) 270,000 -18%
Internal Combustion Engines ≤ 42 MW, summer/winter 420,000
Internal Combustion Engines ≤ 42 MW, other 330,000

Note: * It assumes a FX of AR$60/US$.

 

As SRRYME Resolution No. 1/19, SE Resolution No. 31/20 provides for the application of a coefficient arisen from the unit’s average utilization factor during the last twelve months to the power capacity remuneration. Although the formula remained unchanged for internal combustion engines ≤ 42 MW, in all other cases, if the usage factor is lower than 30%, 60% of the power capacity payment is collected.

Regarding the additional remuneration in the HMRT (hours of high thermal dispatch), which consist of the 50 recorded hours with the highest thermal generation dispatch each month, grouped in two blocks of 25 hours each, the following will be applied to the average generated capacity during such hours:

Period, in AR$/MW-HMRT First 25 HMRT hours Second 25 HMRT hours
Summer (December – February) and Winter (June – August) 45,000 22,500
Other (March – May and September – November) 7,500

As regards the remuneration for generated and operated energy, they remained unchanged in US$ at a FX of AR$60/US$, but set at AR$240/MWh with natural gas, AR$420/MWh with fuel oil, AR$600 with biofuels (except for internal combustion engines, AR$720/MWh) and AR$720/MWh with mineral coal. The remuneration for operated energy was set at AR$84/MWh.

 

Hydro Power Generators

SE Resolution No. 31/20 adjusted the capacity remuneration and added a new HMRT remuneration. The 1.05 factor over the power capacity to compensate the impact of programmed maintenance remained unchanged, as well as the 1.20 factor for units maintaining control structures on river courses and not having an associated power plant.

Scale Capacity
Base Price (AR$/MW-month)
Variation vs. SRRYME Resolution
No. 1/19*
Large HI (Hydroelectric Plants) Capacity > 300 MW 99,000 -45%
Medium HI Capacity > 120 ≤ 300 MW 132,000 -45%
Small HI Capacity > 50 ≤ 120 MW 181,500 -45%
Renewable HI Capacity ≤ 50 MW 297,000 -45%
Large Pumped HI Capacity > 300 MW 99,000 +10%
Medium Pumped HI Capacity > 120 ≤ 300 MW 132,000 -12%

Note: * It assumes a FX of AR$60/US$.

 

As regards the HMRT additional remuneration, the following will be applied to the average operated power capacity during such hours:

Scale Capacity HMRT Price
AR$/MW-HMRT
Large HI Capacity > 300 MW 27,500
Medium HI Capacity > 120 ≤ 300 MW 32,500
Small HI Capacity >50 ≤ 120 MW 32,500
Renewable HI Capacity ≤ 50 MW 32,500
Large Pumped HI Capacity > 300 MW 27,500
Medium Pumped HI Capacity > 120 ≤ 300 32,500

 

Weighted by the following coefficients:

HMRT December – February, June – August Other
First 25 HMRT hours 1.2 0.2
Second 25 HMRT hours 0.6

The prices for generated and operated energy remained unchanged in US$ at a FX of AR$60/US$, though set at AR$210/MWh and AR$84/MWh, respectively. The remuneration for operated energy should correspond with the grid’s optimal dispatch. The provision does not indicate, as it does for thermal generators, which would be the consequence otherwise.

  

Other Considerations

For energy generated from any unconventional source, SE Resolution No. 31/20 provides for a single remuneration value of AR$1,680/MWh, which equals the previous remuneration converted at a FX of AR$60/US$, or 50% of this value if it is generated prior to commercial commissioning.

Furthermore, SE Resolution No. 31/2020 provides for the application of all receivables accrued in favor of generators for the settlement against the repayment of loans for the execution of overhauls, and sets a discount scheme in the generator’s revenues equivalent to the maximum between AR$60/MWh, or AR$42,000/MW-month for the unit’s actual availability. It is worth highlighting that all overhauls financing owed by Pampa were settled under the Agreement for the Regularization and Settlement of Receivables with the WEM (Wholesale Electricity Market).

 

Implementation Criteria for SE Resolution No. 31/20

CAMMESA classifications for our legacy units are detailed below:

Source Power Plant Unit Technology Size Scale
Thermal CTLL (Loma de la Lata) LDLAGT01 GT Large > 50 MW
LDLAGT02 GT Large > 50 MW
LDLAGT03 GT Large > 50 MW
LDLAGT04(1) GT Large > 50 MW
CTG (Güemes) GUEMST11 ST Small ≤ 100 MW
GUEMST12 ST Small ≤ 100 MW
GUEMST13 ST Large > 100 MW
CTGEBA (Genelba) GEBAGT01 CC Large > 150 MW
GEBAGT02
GEBAST01
GEBAGT04(2) GT Large > 50 MW
CPB (Piedra Buena) BBLAST29 ST Large > 100 MW
BBLAST30 ST Large > 100 MW
Hydro HIDISA (Diamante) ADTOHI HI Medium > 120 MW ≤ 300 MW
LREYHB Pumped HI Medium > 120 MW ≤ 300 MW
ETIGHI Renewable HI ≤ 50 MW
HINISA (Los Nihuiles) NIH1HI HI Small > 50 MW ≤ 120 MW
NIH2HI HI Small > 50 MW ≤ 120 MW
NIH3HI(3) HI Small > 50 MW ≤ 120 MW
HPPL (Pichi Picún Leufú) PPLEHI HI Medium > 120 MW ≤ 300 MW

Notes:1 Only 26 MW of the unit apply. 2 It was applied until the commissioning of Genelba Plus’ CC, on July 2, 2020. 3 A 1.20 coefficient applies on remuneration.

GT = gas turbine
ST = steam turbine
CC = combined cycle
HI = hidroelectric

In the case of CTG’s GUEMTG01 and CTGEBA’s GEBATG03 units, pursuant to Section 6 of SE Resolution No. 482/15 and with the agreement of Energía Plus power generators, both the energy delivered to the spot market and the available power capacity not committed under the Energía Plus contracts in force during each period are remunerated based on the items set out for legacy capacity, the cost of the fuel provided by CAMMESA (Compañía Administradora del Mercado Mayorista Eléctrico or the Argentine Wholesale Electricity Market Clearing Company) being excluded from the transaction.

 

thermal-ppas

Energía Plus

In September 2006, the SE (former Secretariat of Energy) approved Resolution No. 1281/06, which establishes certain restrictions on the sale of electricity and implements the Energía Plus service aiming to encourage the development of new power generation supply. These measures imply that:

i. Qualify the power generators, co-generators and self-generators which, as of the date of the publication of SE Resolution No. 1281/06, are neither WEM (Wholesale Electricity Market) agents nor have facilities or interconnection with the WEM;

ii. Applicable power plants should procure fuel and transportation;

iii. The energy used by LU300 (Large users with demands in excess of 300 kW) in excess of the Base Demand (the electrical consumption for the year 2005) qualifies to contract Energía Plus within the MAT (Term Market) at a price negotiated between the parties; and

iv. For new LU300 entering the grid, their Base Demand equals zero.

Within this framework, CTG (Güemes Thermal Power Plant), EcoEnergía (EcoEnergía Co-Generation Power Plant) and CTGEBA (Genelba Thermal Power Plant) provide the Energía Plus service to different WEM clients, which represents 292 MW gross capacity. It is worth highlighting that, effective as from May 2019, CTG transferred its contracts to CTGEBA, selling its electricity in the spot market.

If a power plant cannot meet its Energía Plus demand, it should purchase that power in the spot market at the operated marginal cost. On the other hand, SE Note No. 567/07, as amended, provided that LU300 not purchasing their Surplus Demand within the MAT should pay the CMIEE (Surplus Demand Incremental Average Charge or Cargo Medio Incremental de la Demanda Excedente), and the difference between the real cost and the CMIEE would be accumulated in an individual account on a monthly basis for each LU300 within CAMMESA’s (Compañía Administradora del Mercado Mayorista Eléctrico or the Argentine Wholesale Electricity Market Clearing Company) scope. As from June 2018, pursuant to SE Note No. 28663845/18, the CMIEE became the greater of AR$1,200/MWh or the temporary dispatch surcharge. Additionally, it was provided that, until further instruction, movements in the individual account of each LU300 would temporarily not be recorded.

Energía Plus contract values are mostly denominated in US$; therefore, when expressed in AR$, they are exposed to FX (foreign exchange). Due to the decrease in surplus demand resulting from the economic recession, some LU300 decide not to enter into Energía Plus contracts, and generators must sell their energy at the spot market with lower profitability margins. Additionally, because of the surplus energy from LU300, Energía Plus contracts were affected by the growth in MAT ER (Term Market from Renewable Energy Sources) renewable energy contracts.

PPAs under SE Resolution No. 220/07

By modifying the market conditions, aiming to encourage new investments and increase the generation supply, the SE (former Secretariat of Energy) passed Resolution No. 220/07, which empowers CAMMESA (Compañía Administradora del Mercado Mayorista Eléctrico or the Argentine Wholesale Electricity Market Clearing Company) to enter into ‘WEM (Wholesale Electricity Market) Supply Commitment Agreements’ with WEM Generating Agents for the energy produced with new generation equipment. These are long-term PPAs (Power Purchase Agreement) denominated in US$, and the price payable by CAMMESA should compensate the investment made by the plant at a rate of return to be accepted by the SE. CTLL (Loma de la Lata Thermal Power Plant), CTP (Piquirenda Thermal Power Plant) and CTEB (Ensenada Barragán Thermal Power Plant) have entered into PPAs with CAMMESA under this Resolution, which account for a gross power capacity of 856 MW(1). Moreover, CTEB has an ongoing expansion project to add 280 MW.

Note: (1) It includes CTLL’s gas turbine GT04 power capacity, which is partially committed under this contract.

Agreement to Increase Thermal Generation Availability

In 2014, the Federal Government submitted a proposal to generators for the execution of a new agreement for the increase in thermal generation availability through the application of LVFVDs (Liquidaciones de Ventas sin Fecha de Vencimiento a Definir or Sales Settlements with Maturity Date to be Defined) and the generators’ own resources. CTLL, CTG, CPB, HINISA and HIDISA entered into this agreement, which set out the conditions for the incorporation into CTLL of a high-efficiency gas turbine (105 MW), which was commissioned for service in July 2016, and two engines (15 MW), which are scheduled for commissioning in 2020.

In 2015, CTLL, CTG, CPB, HINISA and HIDISA entered into a new agreement with the Federal Government whereby CTLL would incorporate a new high-efficiency gas turbine (105 MW), as well as investments in renewable energies. However, this agreement was canceled with the implementation of Resolution No. 19/17 of the SEE (Secretariat of Electric Energy). Later, Pampa’s involved generators and CAMMESA (Compañía Administradora del Mercado Mayorista Eléctrico or the Argentine Wholesale Electricity Market Clearing Company) executed an Agreement for the Regularization and Settlement of Receivables with the WEM (Wholesale Electricity Market), and the LVFVD’s balance was collected in August 2019, with the waiver of all LVFVD-related claims.

Note: CTLL (Loma de la Lata Thermal Power Plant), CTG (Güemes Thermal Power Plant), CPB (Piedra Buena Thermal Power Plant), HINISA (Los Nihuiles Hydro Power Plant) and HIDISA (Diamante Hydro Power Plant).

PPAs under SEE Resolution No. 21/16

As a result of the state of emergency in the national electricity sector declared pursuant to Executive Order No. 134/15 of the PEN (Poder Ejecutivo Nacional or National Executive Branch), on March 22, 2016 the SEE (Secretariat of Electric Energy) issued Resolution No. 21/16 launching a call for bids for new thermal power generation capacity with the commitment to making it available through the WEM (Wholesale Electricity Market) for the 2016/2017 summer, 2017 winter, and 2017/2018 summer periods. Successful bidders entered a PPA (Power Purchase Agreement) for a fixed price (in US$/MW-month) and a variable price excluding fuels (in US$/MWh) with CAMMESA (Compañía Administradora del Mercado Mayorista Eléctrico or the Argentine Wholesale Electricity Market Clearing Company), which acted on behalf of distributors and WEM’s large users.

Pampa was awarded the installation of gas turbine GT05 at CTLL (Loma de la Lata Thermal Power Plant) for 105 MW and the construction of CTIW (Ingeniero White Thermal Power Plant) for a 100 MW capacity, both of which have been in service since August and December 2017, respectively. Furthermore, Pampa acquired and developed CTPP (Parque Pilar Thermal Power Plant) for a 100 MW capacity, which was commissioned for service in August 2017.

PPAs under SEE Resolution No. 287/17

On May 10, 2017 the SEE (Secretariat of Electric Energy) issued Resolution No. 287/17 launching a call for tenders for co-generation projects and the closing to CC (Combined Cycle) over existing equipment. The projects should have low specific consumption (lower than 1,680 kcal/kWh with natural gas and 1,820 kcal/kWh with alternative liquid fuels), and the new capacity should not increase electricity transmission needs beyond the existing capacity; otherwise, the cost of the necessary extensions would be borne by the bidder.

Awarded projects were remunerated under a PPA (Power Purchase Agreement) for a term of 15 years. The remuneration is made up of the available power capacity price plus the variable non-fuel cost for the delivered energy and the fuel cost (if offered), less penalties and fuel surpluses. Power capacity surpluses would be remunerated as legacy capacity.

Within this framework, in September 2017 the SEE issued Resolution No. 820/17 awarding only three co-generation projects for a 506 MW power capacity, and in October 2017, pursuant to Resolution No. 926/17, it awarded projects for a total 1,304 MW power capacity, where Pampa was awarded the closing to CC in the Plus unit at CTGEBA (Genelba Thermal Power Plant) for 383 MW. Commercial operations at open cycle started in June 2019, and at closed cycle on July 2, 2020.

Based on the moderate demand growth, the entrance of renewable generation and widespread work delays, through Resolution No. 25/19 of the SRRYME (Secretariat of Renewable Resources and Electricity Market) it was required the ratification of the commercial commissioning dates for the awarded projects. Moreover, it provided the option to extend this date for up to 180 days and established a penalty scheme for the corresponding delays. Pampa ratified Genelba Plus CC’s commercial commissioning date.

 

green-ppas

Introduction

In October 2015, Law No. 27,191 (regulated by Executive Order No. 531/16) was passed, which amends Law No. 26,190 on the promotion of renewable sources of energy. Among other measures, it provided that by December 31, 2025, 20% of the total demand for energy in Argentina should be covered with renewable sources of energy(1). To meet such objective, WEM (Wholesale Electricity Market)’s GU (Large Users) and CAMMESA (Compañía Administradora del Mercado Mayorista Eléctrico or the Argentine Wholesale Electricity Market Clearing Company) should cover 8% of their demand with such sources by December 31, 2017, the percentage rising every two years until this objective is met. The agreements entered with GU and GUDI (Large Distribution Company Users) may not have an average price exceeding US$113/MWh.

Additionally, several incentives are established to encourage renewable energy projects, including tax benefits (advance VAT return, accelerated depreciation on the income tax return, import duty exemptions, etc.) and the creation of the FODER (Fondo para el Desarrollo de Energía Renovables or Fund for the Development of Renewable Energies), which is destined, among other objectives, to the granting of loans, capital contributions, etc. for the financing of these projects.

Note: (1) As from December 2016, CHs (Hydroelectric Power Plants) with a power capacity lower than 50 MW are classified as renewable sources of energy.

RenovAr Program

In 2016, the RenovAr Rounds 1 and 1.5 Programs were launched pursuant to Resolutions No. 71/16 and 252/16 of the MEyM (former Ministry of Energy and Mining), respectively. In Round 1, 29 projects were awarded for a total 1,142 MW (97% of which were wind and solar energy projects), including our 100 MW PEMC (Ingeniero Mario Cebreiro Wind Farm) project in the Province of Buenos Aires, which was commissioned in June 2018. In Round 1.5, 30 projects were awarded for a total 1,281.5 MW (100% of which were wind and solar energy projects). In 2017, the RenovAr Round 2 Program was launched pursuant to MEyM Resolution No. 275/17, under which 88 projects were awarded for a total 2,043 MW (89% of which were wind and solar energy projects). Finally, in 2018, the RenovAr MiniRen Round 3 Program was launched for smaller-scale renewable projects (between 0.5 and 10 MW), and projects were awarded for a total 246 MW.

It is worth highlighting that for all projects under the RenovAr rounds, it was established that all greenhouse gas reductions resulting from the power capacity installed throughout the national territory —including those resulting from any other project accounted for to meet the WEM (Wholesale Electricity Market)’s renewable capacity goals set by Law No. 27,191— should be accounted for by the Federal Government for the meeting of its contribution goal under the United Nations Framework Convention on Climate Change and the Paris Agreement.

MAT ER

Resolution No. 281/17 of the MEyM (former Ministry of Energy and Mining) issued on August 18, 2017 regulated the MAT ER (Term Market from Renewable Energy Sources) regime, which sets the conditions for WEM (Wholesale Electricity Market)’s large users and GUDI (Large Distribution Company Users) to meet their demand supply obligation from renewable sources through the individual purchase within the MAT ER or through self-generation from renewable sources. Furthermore, it regulates the conditions applicable to renewable power generation projects. Specifically, it created the RENPER (Registry of Renewable Electric Power Generation Projects), where such projects should be registered.

Projects destined to supply the MAT ER should not be committed under other remuneration mechanisms (e.g., the RenovAr Program). Surplus power generation exceeding commitments with MAT ER are remunerated up to 10% of the power generation at the minimum price for the applicable technology under the RenovAr Program, and the balance is sold in the spot market.

Furthermore, agreements executed under the MAT ER regime should be administered and managed in accordance with the WEM Procedures. The contractual terms —life, allocation priorities, prices and others, except for the maximum price set forth by Law No. 27,191— may be freely agreed between the parties, although the committed volumes should be limited by the renewable energy produced by the generator or supplied by other generators or suppliers with which it has MAT ER agreements in place.

Pampa registered Pampa Energía Wind Farm, also known as PEPE II and PEPE III projects with the RENPER. It also requested the corresponding dispatch priority under MEyM Resolution No. 281/17, which was granted for the total capacity of both projects. On May 10, 2019, CAMMESA granted the commissioning of PEPE II and PEPE III. The generated energy is sold under PPAs (Power Purchase Agreements) with private parties for an average term of approximately 5 years.

Renewable Energy Distributed Generation

On December 27, 2017, Law No. 27,424 was published, which declares the distributed generation of electric power from renewable sources destined to self-consumption and the possible injection of surpluses into the distribution network to be of national interest. The Law also establishes the distribution utility providers’ obligation to facilitate such injection by guaranteeing free access to the distribution network, notwithstanding the provinces’ own powers.

Executive Order No. 986/18 of the PEN (Poder Ejecutivo Nacional or National Executive Branch) issued in November 2018 and Resolution No. 314/18 of the SGE (former Government Secretariat of Energy) in December 2018 regulated the Regime Encouraging Grid-Integrated Renewable Energy Distributed Generation seeking to reach a 1,000 MW capacity within a term of 12 years.

As regards the billing scheme, it is expected that a balance will be reached between each user-generator’s consumption and injection. Moreover, distributors should file a monthly declaration to CAMMESA (Compañía Administradora del Mercado Mayorista Eléctrico or the Argentine Wholesale Electricity Market Clearing Company) indicating the values corresponding to the electric power injected by users-generators.

 

electricity-tariff

Transener’s Tariff Situation

The Public Emergency and Exchange Rate Regime Reform Law (Law No. 25,561) imposed the obligation on public utilities, such as Transener and its subsidiary Transba, to renegotiate their agreements in force with the Government while continuing supplying electricity services. This situation has significantly affected Transener and Transba’s economic and financial situation.

In May 2005, Transener and Transba signed with the UNIREN (Public Utility Contract Renegotiation and Analysis Unit) the Memorandums of Understanding stipulating the terms and conditions for updating the Concession Agreements. The guidelines of these Memorandums of Understanding provided for the performance of an RTI (Integral Tariff Review) before the ENRE (Ente Nacional Regulador de la Electricidad or National Electricity Regulatory Entity) and the determination of a new tariff regime for Transener and Transba, which should have come into force in 2006, as well as for the recognition of variations in operating costs incurred until the entry into effect of the new tariff regime resulting from the RTI.

Since 2006, Transener and Transba have repeatedly requested the ENRE to regularize compliance with the commitments stipulated in the Memorandum of Understanding, expressing the demand to launch the RTI process. Furthermore, Transener and Transba filed their respective tariff claims for their assessment, the holding of a public hearing and the definition of the new tariff scheme.

Instrumental Agreement

In December 2010 Transener and Transba entered into an Instrumental Agreement to UNIREN’s Memorandum of Understanding with the SE (former Secretariat of Energy) and the ENRE, which mainly provided for the acknowledgment of a credit claim in favor of Transener and Transba for cost fluctuations incurred during the June 2005 –November 2010 period, calculated as per the Cost Variation Index established in the Memorandum of Understanding. These receivables were assigned in consideration of disbursements by CAMMESA (Compañía Administradora del Mercado Mayorista Eléctrico or the Argentine Wholesale Electricity Market Clearing Company), which were executed through loan agreements.

Upon collecting these receivables and still without the RTI, in May 2013 Transener and Transba, respectively, executed with the SE and the ENRE a Renewal Agreement, effective until December 31, 2015, which, among other provisions, acknowledged a credit claim for cost variations recorded during the December 2010 – December 2012 period. In view of the repeated delays in the implementation of the RTI provided for in the Memorandum of Understanding, the SE and the ENRE successively extended the recognition of higher costs up to and including November 2015. In May 2016, upon the expiration of the Renewal Agreement and without any pending recognized receivables, Transener and Transba continued collecting the loans granted by CAMMESA, which were disclosed as liabilities. Finally, on December 26, 2016, Transener executed the last agreement with the SE and the ENRE, which recognized credits for cost variations in favor of Transener and Transba for the December 2015 – January 2017 period. On June 19, 2017, CAMMESA made the last disbursement, thus offsetting all credits for cost variations.

RTI

ENRE Resolutions No. 66/17 and No. 73/17 in February 2017, as amended, established the tariffs effective for the 2017/2021 five-year period. Furthermore, the ENRE established the remuneration update mechanism, the service quality system and applicable penalties, the reward system, and the investment plan to be executed by both companies during such period. In October 2017, the ENRE issued Resolutions No. 516/17 and No. 517/17 partially upholding the Motions for Reconsideration filed by Transener and Transba and establishing, retroactively as of February 2017, a AR$8,629 million and AR$3,575 million recognized capital base and AR$3,534 million and AR$1,604 million annual regulated income for Transener and Transba, respectively.

The purpose of the semiannual adjustment mechanism stipulated in the Integral Tariff Review (RTI) is to keep real-term values for remunerations collectable by Transener and Transba during the RTI’s five-year period. The adjustment formula takes into consideration the variations during such semester in the IPIM (Wholesale Domestic Price Index), ‘Manufactured Products’ item, the CPI (Consumer Price Index) and the Salary Index published by the INDEC (Instituto Nacional de Estadística y Censos de Argentina or National Institute of Statistics and Censuses), which are weighed based on the cost structure and average investments for the 2017-2021 period in the RTI. This mechanism contemplates a trigger clause that weighs the IPIM and the CPI semiannual variations published by the INDEC, ascertained at a variation equal to or higher than 5%.

For the December 2016 – June 2017 period, the trigger clause reached 9.02%, and, therefore, the semiannual adjustment for Transener and Transba remuneration was activated, but deferred until December 15, 2017, when ENRE issued Resolutions No. 627/17 and No. 628/17 updating Transener and Transba’s remunerations by 11.35% and 10.96%, respectively, for the December 2016 – June 2017 period, retroactively to August 1, 2017.

ENRE Resolutions No. 37/18 and No. 38/18 of February 19, 2018, later amended by ENRE Resolutions No. 99/18 and 100/18 on April 5, 2018, updated Transener and Transba’s remunerations by 24.15% and 23.39%, respectively, for the December 2016 – December 2017 period, effective as from February 1, 2018. On November 16, 2018, the ENRE issued Resolutions No. 280/18 and No. 281/18, updating Transener and Transba’s remunerations by 42.55% and 43.25%, respectively, for the December 2016 – June 2018 period, effective as from August 1, 2018.

On March 22, 2019, the ENRE issued Resolutions No. 67/19 and No. 68/19 updating Transener and Transba’s remunerations by 78.41% and 81.26%, respectively, for the December 2016 – December 2018 period, effective as from February 1, 2019. On September 25, 2019, the ENRE issued Resolutions No. 269/19 and No. 267/19 updating Transener and Transba’s remunerations by 112.41% and 115.75%, respectively, for the December 2016 – June 2019 period, retroactively to August 1, 2019.

The Solidarity Law (Law No. 27,541), which entered into effect on December 23, 2019, provided that electricity tariffs under federal jurisdiction would remain unchanged and contemplates the possibility to perform an extraordinary review of the current RTI for a maximum term of up to 180 days. As of the date hereof, Transener did not received instructions from the ENRE on the semiannual remuneration update which, according to the RTI, should have been applied as from February 1, 2020 corresponding to the December 2016 – December 2019 period.

Distribution of Transmission Costs among WEM (Wholesale Electricity Market) Users

Resolution No. 1085/17 of the SEE (Secretariat of Electric Energy) issued on November 28, 2017 and effective as from December 1, 2017, established the methodology for the distribution of costs associated with the remuneration of transmission companies among its users (distributors, large users, self-generators and generators). These costs are distributed based on the demand and/or contribution of energy by each WEM agent directly and/or indirectly associated to the DisTro (High-Voltage Electric Power Transmission System), after discounting costs assigned to generating agents as operational and maintenance costs for connection and transformation equipment.

It is worth highlighting that prices payable by distribution companies in consideration of electric power transmission within the WEM are stabilized for their payment by distributors and are calculated together with each Seasonal Programming or Quarterly Reprogramming. In the case of distributing agents whose demand is connected to different DisTros, their demand’s percentage corresponding to each DisTro will be established, and the price will contemplate the demand and the price on a weighted basis. Furthermore, prices applicable to large users within the WEM are calculated in the economic transaction on a monthly basis. In the case of WEM large users not directly associated with the high-voltage transmission and/or DisTro, the applicable monthly value will be that corresponding to the connecting agent.

Edenor’s Tariff Situation

Memorandum of Understanding with the Federal Government

In February 2006, Edenor entered into a Contract Renegotiation Memorandum of Understanding with the UNIREN (Public Utility Contract Renegotiation and Analysis Unit), which established, effective as from November 2005, a 23% increase in the average VAD (Distribution Added Value), as well as a 5% additional VAD increase to be allocated to certain specific investments in capital goods. Furthermore, it provides for the inclusion of a social tariff, quality standards for the service to be rendered and a minimum investment plan in the electricity grid to be performed by Edenor, as well as the performance of an RTI (Integral Tariff Review). Upon the failure to perform the RTI, the SE (former Secretariat of Energy) and the ENRE (Ente Nacional Regulador de la Electricidad or National Electricity Regulatory Entity) passed several transitory measures seeking to reduce Edenor’s operating and asset deterioration resulting from the tariff freeze. The background and the current tariff situation are disclosed below.

SE Resolution No. 250/13

Since May 2013, the SE provided for the recognition of costs owed to Edenor resulting from the partial application of the MMC (Cost Monitoring Mechanism), the result of which was lower than the actual increase. It was stipulated in the 2007 Contractual Renegotiation Agreement, which was not duly passed on to tariffs. This measure was implemented by SE Resolution No. 250/13 and its subsequent extensions, which allowed for the offsetting of this recognition with Edenor’s liabilities under PUREE (Program for the Rational Use of Electric Power) and with CAMMESA (Compañía Administradora del Mercado Mayorista Eléctrico or the Argentine Wholesale Electricity Market Clearing Company) for energy purchases. However, in February 2016 the SE issued Resolution No. 6/16 abrogating the MMC.

ENRE Resolution No. 347/12

ENRE Resolution No. 347/12 applied a differential fixed amount to each of the different tariff categories, except for customers exempt from paying the tariff scheme provided for by ENRE Resolution No. 628/08. Such amounts —which continued to be deposited in a special account and were used exclusively for the execution of infrastructure and corrective maintenance works in Edenor’s facilities within the concession area— were managed by the FOCEDE (Fondo de Obras de Consolidación y Expansión de Distribución Eléctrica or Fund for Electricity Distribution Expansion and Consolidation Works). ENRE Resolution No. 2/16 terminated the FOCEDE trust on January 31, 2016 and established a new system for the funds collected pursuant to ENRE Resolution No. 347/12, which were managed by Edenor. With the implementation of the RTI in February 2017, these amounts ceased to be charged as a special item on customer bills.

Loan Agreements – Extraordinary Investments Plan

Due to the delay in obtaining the RTI, the Federal Government granted to Edenor loans for the conduction of the investments plan it may deem appropriate. Pursuant to Resolution No. 7/16 of the MEyM (former Ministry of Energy and Mining), CAMMESA suspended, as from February 2016 and until receiving further instructions, all effects from the executed loan agreements and the transfer of resources to distribution companies on behalf of the FOCEDE trust and, therefore, the new works plan would be financed exclusively with tariff proceeds. The amounts owed by Edenor under loan agreements and works were offset by the Federal Government in the Liabilities Regularization Agreement executed on May 10, 2019.

SE Resolution No. 32/15

SE Resolution No. 32/15, passed in March 2015, implemented a transitory increase in Edenor’s income as from February 2015 to be charged against the RTI. Moreover, pursuant to this provision, the amounts collected under the PUREE program were deemed as part of Edenor’s income. This Resolution did not generate tariff increases for customers but was directly transferred by the Federal Government.

However, in January 2016 ENRE Resolution No. 7/16 ordered the performance of all necessary acts to conduct Edenor’s RTI, annul the tariff schemes of SE Resolution No. 32/15, and adjust the VAD to be charged against the RTI, thus canceling the PUREE and suspending the investments loan agreements entered into with Edenor. Consequently, the ENRE issued Resolution No. 1/16 and 2/16 granting a new tariff scheme for Edenor effective as from February 2016. In September 2016, Edenor filed its tariff proposal for the RTI, clarifying that it does not contemplate the value Edenor assigns to damages resulting from the failure to timely and properly implement the Memorandum of Understanding or the collection of income necessary to face the liabilities Edenor has incurred as a result.

RTI

ENRE Resolution No. 63/17, as amended, established the final tariff schemes, the review of costs, required quality levels and other rights and obligations by Edenor for the five-year period starting February 2017. A 42% cap was set in the VAD increase resulting from the Integral Tariff Review (RTI) as from February 2017, the remaining increase being completed in November 2017 and February 2018. The VAD difference resulting from the gradual application was updated in real terms and incorporated in 48 installments payable as from February 2018. The tariff schemes included the prices established in the seasonal programming for the February – April 2017 period under Resolution No. 20/17 of the SEE (Secretariat of Electric Energy).

However, both the CPD (Own Distribution Cost or Costo Propio de Distribución) update contemplated for August 2017 and the VAD increase scheduled for November 2017 were deferred to December 2017, which tariff schemes were fixed pursuant to ENRE Resolution No. 603/17 for the December 2017 – January 2018 two-month period, also contemplating the 18% VAD increase and the 11.6% CPD update, adjusted retroactively as of the dates they should have been implemented.

Furthermore, ENRE Resolution No. 33/18 published a new tariff scheme, effective as from February 2018, applying the last 17.8% VAD increase, the 22.5% CPD update, and considered the total deferred amount of AR$6,343 million recoverable in 48 installments, subject to an annual review each February for the years 2019 through 2021. These Resolutions included electricity prices and discount schemes for users benefiting from the social tariff and evidencing consumption savings, as provided for in SEE Resolutions No. 1091/17 for the December 2017 – January 2018 and February – April 2018 periods, which were later extended until October 2018 pursuant to SEE Provision No. 44/18.

It is worth highlighting that the 22.5% CPD update contemplated a -2.51% E-factor adjustment stimulating efficiency resulting from the RTI as an element geared at passing on to the distributor’s users the expected efficiency gains as from i) factor X, which captures gains resulting from management optimization and the existence of economies of scale, which reduces the CPD; and ii) investments factor Q, which captures the impact of the cost of capital and the evolution of exploitation costs resulting from investments made by the company, which increases the CPD.

As regards the CPD update scheduled for August 2018, Edenor agreed with the MinEn (former Ministry of Energy) on a 50% deferral. Moreover, the MinEn agreed to implement the actions necessary to regularize the Memorandum of Understanding entered into in 2007 and the Framework Agreement. ENRE Resolution No. 208/18 provided for a 15.85% update in the CPD, 7.925% of which was applicable as from August 2018, and the balance in six monthly consecutive installments effective as from February 2019.

Furthermore, SEE Provisions No. 75/18 and 97/18 established for the August 2018 – January 2019 period the power capacity reference price at AR$10,000/MW-month, the stabilized price for transmission in the extra high voltage system at AR$64/MWh, and a price for main distribution based on the distribution company which, in the case of Edenor, amounted to AR$0/MWh. Energy reference prices were set at AR$2,283/MWh for GUDI (Large Distribution Company Users) and at AR$1,470/MWh for the remaining users. As regards the social tariff, the criteria set by SEE Resolution No. 1091/17 for subsidies to users and discounts for savings remained in effect.

Effective as from February 2019, Resolution No. 366/18 of the SGE (former Government Secretariat of Energy) abrogated SEE Resolution No. 1091/17 and, consequently, the Federal Government’s social tariff and the savings discount scheme, and also set a power capacity reference price of AR$80,000/MW-month, with 25% and 20% increases in the months of May and August, respectively, effective until October 2019. The stabilized price for transmission in the extra high voltage system and the distributor-based main distribution price remained unchanged. Energy reference prices were set at AR$2,762/MWh for GUDI for the February – October 2019 period, and at AR$1,852/MWh for the remaining users as from February 2019, with 5% increases in the months of May and August, effective until October 2019.

ENRE Resolution No. 25/19 approved the tariff scheme effective as from February 2019, which reflected the new seasonal prices described in SGE Resolution No. 366/18, and ENRE Resolution No. 27/19 of March 2019 established the 24%(1) CPD update corresponding to the July 2018 – January 2019 semester, retroactive to February 2019, and a 7.925% increase which was timely deferred in August 2018, retroactive to that date. Compensatory amounts for the retroactivity were collected in five installments.

In April 2019, SGE Resolution No. 366/18 was partially amended by Resolution No. 14/19 of the SRRYME (Secretariat of Renewable Resources and Electricity Market): increases planned for May and August 2019 for the power capacity reference price and increases contemplated for residential users were suspended, whereas energy reference prices increased by 5% in May and August 2019 for GUDI, and by 7% in May and August 2019 for the rest of non-residential users. Moreover, SRRYME Resolutions No. 26/19 and 38/19 approved the seasonal programming for the August – October 2019 and November 2019 – April 2020 periods, respectively, prices remaining unaltered until April 2020. However, as of the date hereof these increases in seasonal prices for non-residential users have not been passed on to new tariff schemes.

On September 19, 2019 Edenor agreed with the Federal Government to postpone the 19.05% CPD update for August 1, 2019 until January 1, 2020. Moreover, the continuity of retroactive amounts applied in the March – July 2019 period for the timely deferred CPD was allowed, the balance being recoverable in 7 monthly consecutive installments as from January 2020. Besides, the payment of penalties by Edenor was postponed until March 1, 2020 in 6 monthly installments. However, with the entry into effect of the Solidarity Law (Law No. 27,541), on December 27 the ENRE instructed Edenor to maintain the current tariff schemes until June 2020, suspending all planned updates both in the CPD and in the seasonal price. It also contemplates the possibility of performing an RTI review for up to 180 days as from the Law’s effective date.

Note: (1) Including the -1.59% E Factor stimulating efficiency.

Regularization of Liabilities and Transfer of Concession Jurisdiction

On February 28, 2019, the Federal Government entered into an agreement with the Province of Buenos Aires and the City of Buenos Aires for the transfer of Edenor’s concession jurisdiction. The Province of Buenos Aires and the City of Buenos Aires immediately bore the social tariff outlays, a bipartite regulatory body would be created, and the Federal Government undertook to terminate pending issues such as the breach of the 2006 Memorandum of Understanding, among others. Until the effective date of such transfer, the national regulatory framework would apply.

Moreover, on May 10, 2019, Edenor and the Federal Government agreed to end to the reciprocal claims regarding the 2006 – 2016 Tariff Transition Period. Edenor waived all rights and proceedings against the Federal Government, including the lawsuit brought by Edenor in 2013 upon the breach of the 2006 Memorandum of Understanding, undertook to execute investments additional to the RTI in the following 5 years, and to pay certain penalties to users and generated income tax, entailing a disbursement for a total approximate amount of AR$7,600 million over a term of 5 years. For its part, the Federal Government offset the obligations arising during such period, such as Edenor’s commercial debts for energy purchases, investment loans granted by CAMMESA and penalties owed to the National Treasury, without this implying any fund inflow for Edenor.

However, with the entry into effect of the Solidarity Law, as from December 23, 2019, the ENRE was appointed as Edenor’s regulatory body until December 31, 2020. Moreover, Edenor is currently unaware of the guidelines to follow regarding consumptions of shantytowns with community meters for non-recognized and future periods.