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REGULATORY FRAMEWORK | 12 Months Ended
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Dec. 31, 2022
Regulatory Framework |
REGULATORY FRAMEWORK | NOTE 2: REGULATORY FRAMEWORK
| 2.1 | Generation
2.1.1 Generation units The Company’s revenues related to this segment come from: i) sales contracts with large users within the MAT (Resolutions No. 1,281/06 and No. 281/17); ii) supply agreements with CAMMESA (Resolutions No. 220/07, No. 21/16, No. 287/17 and Renovar Programs) and iii) sales to the Spot market pursuant to the provisions applicable within the WEM administered by CAMMESA (SE Resolution No. 31/20 as from February 2020, SE Resolution No. 440/21 as from February 2021, SE Resolution No. 238/22 as from February 2022 and SE Resolution No. 826/22 as from September 2022). The Company’s generating units, held directly and through its subsidiaries and joint ventures, are detailed below:
Schedule of generating units in operation |  |  |  |
In operation as of 12.31.2022: |  |  |
Generator | Generating unit | Tecnology | Power | Applicable regime (1)
CTG | GUEMTG01 | TG | 100 MW | Energy Plus Res. No. 1,281/06
CTG | GUEMTV11 | TV | ≤100 MW | Resolution No. 826/22
CTG | GUEMTV12 | TV | ≤100 MW | Resolution No. 826/22
CTG | GUEMTV13 | TV | >100 MW | Resolution No. 826/22
Piquirenda | PIQIDI 01-10 | MCI | 30 MW | Resolution No. 826/22
CPB | BBLATV29 | TV | >100 MW | Resolution No. 826/22
CPB | BBLATV30 | TV | >100 MW | Resolution No. 826/22
CT Ing. White | BBLMD01-06 | MCI | 100 MW | Resolution No. 21/16
CTLL | LDLATG01/TG02/TG03/TV01 | CC | >150 MW | Resolution No. 826/22
CTLL | LDLATG04 | TG | 105 MW | Res. No 220/07 (75%)
CTLL | LDLATG05 | TG | 105 MW | Resolution No. 21/16
CTLL | LDLMDI01 | MCI | 15 MW | Resolution No. 826/22
CTGEBA | GEBATG01/TG02/TV01 | CC | >150 MW | Resolution No. 826/22
CTGEBA | GEBATG03 | TG | 169 MW | Energy Plus Res. No. 1,281/06
CTGEBA | GEBATG03/TG04/TV02 | CC | 400 MW | Resolution No. 287/17
Ecoenergía | CERITV01 | TV | 14 MW | Energy Plus Res. N° 1,281/06
CT Parque Pilar | PILBD01-06 | MCI | 100 MW | Resolution No. 21/16
CTB | EBARTG01 - TG02 | TG | >50 MW | Resolution No. 826/22 (2)
HIDISA | AGUA DEL TORO | HI | HI – Media 120<P≤300 | Resolution No. 826/22
HIDISA | EL TIGRE | HR | Renewable ≤ 50 | Resolution No. 826/22
HIDISA | LOS REYUNOS | HB | HB – Media 120<P≤300 | Resolution No. 826/22
HINISA | NIHUIL I - II - III | HI | HI – Small 50<P≤120 | Resolution No. 826/22
HPPL | PPLEHI | HI | HI – Media 120<P≤300 | Resolution No. 826/22
P.E. M. Cebreiro | CORTEO | Wind | 100 MW | Renovar
PEPE II | PAMEEO | Wind | 53 MW | MATER Res. No. 281/17
PEPE III | BAHIEO | Wind | 53 MW | MATER Res. No. 281/17
PEPE IV | BAHIEO | Wind | 18 MW | MATER Res. No. 281/17
PE Arauco | AR21EO | Wind | 99.75 MW | Renovar
(1) Surplus power capacity and energy are remunerated in the spot market.
(2) During the month of April 2022 the contract under Resolution No. 220/07 of CTB have ended, since then, power and energy have been remunerated in the spot market.
Schedule of generating units in construction |  |  |  |
In construction: |  |  |  |
Generator | Tecnology | Capacity | Applicable regime |
CTB | CC | 280 MW | Resolution No. 220/07 |
PEPE IV | Wind | 63 MW | MATER Res. No. 281/17 |
PEPE VI | Wind | 94.5 MW | MATER Res. No. 281/17 |
2.1.2 Sales contracts with large users within the MAT 2.1.2.1 Energy Plus Aiming to encourage new generation works, in 2006, the SE approved Resolution No. 1,281/06 in which established a specific regime which remunerates newly installed generation sold to a certain category of Large Users at higher prices. The Energy Plus service consists of the offer of additional generation availability by generators, co-generators and self-generators which, as of the date of publication of SE Resolution No. 1,281/06, were not WEM agents or did not have facilities or an interconnection with the WEM. Considering that:
| - | These plants should have fuel supply and transportation facilities;
| - | The energy used by GU300 in excess of the base demand (energy consumption for 2005 year) qualifies for Energy Plus agreements within the MAT at a price negotiated between the parties; and
| - | For new GU300 entering the system, their base demand will equal zero.
If a generator cannot meet the power demand by an Energy Plus customer, it should purchase that power in the market at the operated marginal cost, or, alternatively, support the committed demand in case of unavailability through agreements with other Energía Plus generators. Currently, the Company has Power Availability agreements in force with other generators whereby, in case of unavailability, it may purchase or sell power to support the contracts mutually. Furthermore, the SE, through Note No. 567/07, as amended, established that GU300 not purchasing their surplus demand in the MAT should pay the Average Incremental Charge of Surplus Demand (“CMIDE”). As from the month of June 2018, pursuant to SE Note No. 28663845/18, the CMIDE became the greater of $1,200/MWh or the temporary dispatch surcharge. Under this regime, the Company —through its power plants Güemes, EcoEnergía and Genelba— sells its energy and power capacity for a maximum amount of 283 MW. The values of Energy Plus contracts are mostly denominated in U.S. dollars. 2.1.2.2 Renewable Energy Term Market (“MATER” Regime) Pursuant to Resolution No. 281/17, the MEyM regulated the MATER Regime with the purpose of setting the conditions for large users within the WEM and WEM distributing agents’ large users covered by Section 9 of Law No. 27,191 to meet their demand supply obligation from renewable sources through the individual purchase within the MATER from renewable sources or self-generation from renewable sources. Projects destined to the supply of electric power from renewable sources under the MATER Regime may not be covered by other remuneration mechanisms, such as the agreements under the Renovar rounds. Surplus energy is sold in the spot market. Finally, contracts executed under the MATER Regime are administered and managed in accordance with the WEM procedures. The contractual terms —life, allocation priorities, prices and other conditions, notwithstanding the maximum price set forth in Section 9 of Law No. 27,191— are freely agreed between the parties, although the committed electricity volumes are limited by the electric power from renewable sources produced by the generator or supplied by other generators or suppliers with which it has purchase agreements in place. Resolution No. 370/22 was passed on May 16, 2022, which expanded the MATER system allowing for the sale of renewable energy under this system to meet the GUDI and distribution utility company’s demand. Under this resolution, the Company, through its PEPE II, III and IV wind farms, sells energy for up to 124 MW. Additionally, the Company has started selling third-party generators’ renewable energy for an approximate volume of 2 MW. After the fiscal year closing, took place the commissioning of 4 additional wind turbines with an incremental capacity of 18 MW. For further information regarding PEPE IV project, see Note 17.1. 2.1.2.3 MATER dispatch priority SE Resolution No. 551/21 published on June 16, 2021 modified the dispatch priority maintenance system established by Resolution No. 281/17. Overall, it replaces the granting of a security for the maintenance of the dispatch priority by the payment of a quarterly installment of US$ 500/MW until commissioning within the declared term or a maximum term of 24 months as from the priority assignment. It also established certain conditions for obtaining an extension in the committed commissioning date, which, according to the project development level and the requested extension term, requires a payment between 500 and 1,500 US$/MW/month. Additionally, it allows projects with an assigned dispatch priority but not yet commissioned to continue their execution keeping the dispatch priority, or to waive such priority, thus releasing the transmission capacity. The Company, as owner of the Wind Farm project, located in Las Armas, Province of Buenos Aires, notified its decision to waive the timely granted dispatch priority, and recovered the security it had provided. As a result, CAMMESA notified that the already initiated execution of the security was determined to be moot as it had no further claim against the Company; therefore, as of September 30, 2021, the amount of US$ 12.5 million recorded for to such effect was recovered and disclosed under the item “Other operating income” of the Consolidated Statement of Comprehensive Income. Under the MATER calls for tenders for the third quarter of 2021 and 2022, the Company was awarded a 36 MW and 41 MW dispatch priority, respectively, for the expansion of the PEPE III wind farm. For further information on the extension project aforementioned, see Note 17.1. 2.1.3 Supply Agreements with CAMMESA 2.1.3.1 SE Resolution No. 220/07 Aiming to encourage new investments to increase the generation offer, the SE passed Resolution No. 220/07, which empowers CAMMESA to enter into 220 Agreement with WEM Generating Agents for the energy produced with new equipment. These will be long-term agreements and the price payable by CAMMESA should compensate for the investments made by the agent at a rate of return to be accepted by the SE. Within the framework of this resolution, the Company has remunerated units under 220 agreements for 79 MW and 280 MW, through Loma la Lata thermal power plant and as from the closing to combined cycle’s commissioning at Ensenada de Barragán thermal power plant, owned by CTB, respectively (see Note 5.2.3). 2.1.3.2 SE Resolution No. 21/16 As a result of the state of emergency in the national electricity sector, on March 22, 2016, the SE issued Resolution No. 21/16 calling for parties interested in offering new thermal power generation capacity with the commitment to making it available through the WEM for the 2016/2017 summer, 2017 winter, and 2017/2018 summer periods. For the awarded projects, wholesale power purchase agreements were entered into with CAMMESA for a term of 10 years, with a remuneration made up of the available power capacity price plus the variable non-fuel cost for the delivered energy and the fuel cost (if appropriate), less penalties and fuel surpluses. Surplus power capacity is sold in the spot market. Pursuant to this resolution, the Company, through its Loma de la Lata, Ingeniero White and Pilar thermal power plants, has effective agreements with CAMMESA for the sale of energy and power capacity for a total 305 MW. 2.1.3.3 SE Resolution No. 287/17 On May 10, 2017 the SE issued Resolution No. 287/17 launching a call for tenders for co-generation projects and the closing to CC 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 exceed the existing electric power transmission capacity; otherwise, the cost of the necessary extensions will be borne by the bidder. Pursuant to this regulation, the Company, through its Genelba thermal power plant, has entered into a wholesale power purchase agreement with CAMMESA for the sale of energy and power capacity for a total 400 MW, for a term of 15 years. 2.1.3.4 Renovar Programs In order to meet the objectives, set by Law No. 26,190 and Law No. 27,191 promoting the use of renewable sources of energy, the MEyM called for open rounds for the hiring of electric power from renewable sources (Renovar Programs, Rounds 1, 1.5 and 2) within the WEM. These calls aimed to assign power capacity contracts from different technologies (wind energy, solar energy, biomass, biogas and small hydraulic developments with a power capacity of up to 50 MW). For the awarded projects, renewable electric power supply agreements were executed for the sale of an annual committed electric power block for a term of 20 years. Additionally, several measures were established to promote the construction of projects for the generation of energy from renewable sources, including tax benefits (advance VAT reimbursement, equipment’s accelerated depreciation in the income tax, import duty exemptions, etc.) and the creation of a fund for the development of renewable energies destined, among other objectives, to the granting of loans and capital contributions for the financing of such projects. On December 27, 2021, the SE passed Resolution No. 1,260/21 to address issues regarding the projects under the different Renovar rounds that did not meet committed commissioning terms. Upon satisfaction of certain conditions, the resolution gives project awardees the option to: i) terminate the current contract with CAMMESA against the payment of a sum of money; ii) amend the contract and extend the term for commissioning against a reduction in the contract price and term; iii) commission the project for a power capacity lower than that committed initially. Under the Renovar programs, the Company, through Greenwind, has a supply contract in place with CAMMESA for a total of 100 MW, and in December 2022 it incorporated an additional 99.75 MW following the acquisition of Arauco wind farm (see Note 5.1.5). 2.1.3.5 RenMDI Call SE Resolution No. 36/23 launched a national and international call for tenders to select renewable energy generation projects with a twofold objective: i) the substitution of forced generation (line 1) and ii) the diversification of the energy matrix (line 2). The tender form establishes the following maximum power capacities to be awarded: (i) 500 MW distributed among 6 regions for line 1 and (ii) 120 MW throughout the national territory for line 2. The projects under line 2 will have no priority over other renewable projects. Projects will be remunerated under a supply agreement executed with CAMMESA for a term of 15 years from the project’s commissioning. Until commissioning, the tenderer will meet a payment scheme (an initial payment and quarterly payments), which will be allocated to a special account to be administered by CAMMESA through the the “Electricity Supply Transportation Works Fund” trust (“FOTAE”) for the transmission system’s expansion. The tender submission deadline is April 27, 2023. As of the date of issuance of these Consolidated Financial Statements, Pampa is evaluating the possibility of participating in the call. 2.1.3.6 Remuneration for combined cycles SE Resolution No. 59/23 dated February 7, 2023 established an opt-in system under which combined cycles’ owners could execute an availability and efficiency optimization agreement with CAMMESA. The agreement contemplates an availability commitment for 85% of the net power capacity for a maximum term of 5 years, and sets a US$ 2,000/Mw-month remuneration for the power capacity made available and the dollarization of the energy price based on the fuel used (US$ 3.5/MWh for natural gas and US$ 6.1/MWh for fuel oil and gas oil). Besides, it provides for a 35% and 15% reduction in the remuneration collectible for guaranteed power capacity for generators with availability commitments in the spot market for the summer-winter and autumn-spring periods, respectively. The opt-in application form should be submitted to CAMMESA within a term of 90 calendar days. As of the date of issuance of these Consolidated Financial Statements, the Company is currently evaluating the resolution. 2.1.4 Remuneration at the Spot market On February 27, 2020, SE Resolution No. 31/20 was published in the BO, applicable as from February 2020, established remunerative items based on technology and scale with prices in pesos and set an additional remuneration, in pesos, for the power capacity generated during the hours of maximum thermal demand of the month, taking into consideration the average power capacity generated by thermal generators and the average power capacity operated by hydroelectric generators. Besides, SE Resolution No. 31/20 set a monthly remuneration update scheme with a factor contemplating a 60% CPI and 40% IPIM adjustment. However, on April 8, 2020, through Note No. 2020-24910606-APN-SE#MDP, the SE instructed CAMMESA to postpone the application of this automatic adjustment mechanism. On May 19, 2021, SE Resolution No. 440/21 provided for a 29% increase in spot generation remuneration values, and repealed the automatic adjustment mechanism established by SE Resolution No. 31/20. In November 2021, SE Resolution No. 1,037/21, instrumented through Note NO-2021-108163338-APN-SE#ME, provided for an additional transitional remuneration for generated energy and suspended the application of the utilization factor for economic transactions comprised between September 1, 2021 and February 28, 2022. On April 21, 2022, SE Resolution No. 238/22 was published in the BO. This resolution provided a 30% increase in spot generation remuneration values from the February 2022 economic transaction, and an additional 10% increase from the June 2022 economic transaction. It also abrogated the application of the utilization factor and the additional transitional remuneration set by SE Resolution No. 1,037/21. On December 14, 2022, through SE Resolution No. 826/22, the spot remuneration values were modified considering the following increases: i) 20% from the September 2022 economic transaction; ii) 10% from the December 2022 economic transaction; iii) 25% from the February 2023 economic transaction; and iv) 28% from the August 2023 economic transaction. Additionally, SE Resolution No. 826/22 replaced the remuneration scheme at hours of maximum thermal demand with a differentiated remuneration scheme at peak hours from the November 2022 economic transaction. The applicable remunerations, based on technology and resolution, are detailed below. The amounts reported under SE Resolution No. 238/22 and SE Resolution No. 826/22 correspond to tariffs applicable from the June 2022 and December 2022 economic transactions, respectively. 2.1.4.1 Remuneration for Available Power Capacity 2.1.4.1.1 Thermal Power Generators A minimum remuneration for power capacity based on technology and scale was established, and generating, co-generating and self-generating agents owning conventional thermal power plants were allowed to offer guaranteed availability commitments for the energy and power capacity generated by their units and not committed under sales contracts with large users within the MAT and supply agreements with CAMMESA. Availability commitments are tendered 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), the thermal generators’ remuneration for committed power capacity being proportional to their compliance. The minimum remuneration for generators with no availability commitments includes the following scales and prices:
Schedule of minimum remuneration to thermal generators |  |  |  |
Technology / Scale | SE No. 31/20 ($ / MW-month) | SE No. 440/21 ($ / MW-month) | SE No. 238/22 ($ / MW-month) | SE No. 826/22 ($ / MW-month)
Large CC Capacity > 150 MW | 100,650 | 129,839 | 185,670 | 245,084
Large TV Capacity > 100 MW | 143,550 | 185,180 | 264,807 | 349,546
Small TV Capacity ≤ 100 MW | 171,600 | 221,364 | 316,551 | 417,847
Large GT Capacity > 50 MW | 117,150 | 151,124 | 216,107 | 285,262
The remuneration for guaranteed power capacity to generators with availability commitments is:
Schedule of remuneration for thermal generators with guaranteed power capacity |  |  |  |
Period | SE No. 31/20 ($ / MW-month) | SE No. 440/21 ($ / MW-month) | SE No 238/22 ($ / MW-month) | SE No 826/22 ($ / MW-month)
Summer – Winter | 360,000 | 464,400 | 664,092 | 876,601
Fall - Spring | 270,000 | 348,300 | 498,069 | 657,451
In the case of thermal power plants with a power capacity equal to or lower than 42 MW in total, a differential remuneration was applied until its elimination on August 2022. In the same way, a coefficient derived from the average utilization factor over the unit’s last twelve months was applied to the power capacity remuneration: with a minimum 70% of the utilization factor, 100% of the power capacity payment is collected; if the utilization is between 30% and 70%, the power capacity payment ranges from 70% to 100%; and if the utilization factor is lower than 30%, 70% of the power capacity payment was collected until January 2020 and 60% of the power capacity payment is collected as from February 2020. The application of this factor was suspended in 2021 and finally abrogated from February 2022 (see Note 2.1.4.3). For the February 2020 to October 2022 period, an additional remuneration for the hours of maximum thermal requirement of the month (hmrt) was established, which corresponds to the 50 hours with the largest dispatch of thermal generation of each month divided into two blocks of 25 hours each, applying the following prices to the average generated power:
Schedule of additional remuneration to thermal generators |  |  |  |  |  |
Period | SE No. 31/20 | SE No. 440/21 | SE No. 238/22
First 25 hours ($ / MW-hmrt) | Second 25 hours ($ / MW-hmrt) | First 25 hours ($ / MW-hmrt) | Second 25 hours ($ / MW-hmrt) | First 25 hours ($ / MW-hmrt) | Second 25 hours ($ / MW-hmrt)
Summer – Winter | 45,000 | 22,500 | 58,050 | 29,025 | 83,012 | 41,506
Fall - Spring | 7,500 | - | 9,675 | - | 13,835 | -
2.1.4.1.2 Hydroelectric Generators Power capacity 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 operation as turbine and pump is considered to calculate availability. The base remuneration includes the following scales and prices:
Schedule of hydroelectric generators by technology and scales values |  |  |  |
Technology / Scale | SE No. 31/20 ($ / MW-month) | SE No. 440/21 ($ / MW-month) | SE No. 238/22 ($ / MW-mes) | SE No. 826/22 ($ / MW-mes)
Medium HI Capacity > 120 ≤ 300 MW | 132,000 | 170,280 | 243,500 | 321,421
Small HI Capacity > 50 ≤ 120 MW | 181,500 | 234,135 | 334,813 | 441,953
Medium Pumped HI Capacity > 120 ≤ 300 MW | 132,000 | 170,280 | 243,500 | 321,421
Renewable HI Capacity ≤ 50 MW | 297,000 | 383,130 | 547,876 | 723,196
The payment for power capacity is determined by the actual capacity, hours of unavailability due to programmed and/or agreed maintenance are not computed for the calculation of the remuneration. However, to consider the incidence of programmed maintenance works in power plants, SME Note No. 46631495/19 provided for the application of a 1.05 factor over the power capacity payment. In the case of hydroelectric power plants maintaining control structures on river courses and not having an associated power plant, a 1.20 factor is applied to the plant at the headwaters. Furthermore, for the February 2020 to October 2022 period, an additional remuneration was set for the hours of maximum thermal demand (hmrt), corresponding to the 50 hours with the largest dispatch of thermal generation in each month, divided into two blocks of 25 hours each: Generation units > 50 MW and ≤ 300 MW
Schedule of hydroelectric generators by technology and scales values |  |  |  |  |  |
Period | SE No. 31/20 | SE No. 440/21 | SE No. 238/22
First 25 hours ($ / MW-hmrt) | Second 25 hours ($ / MW-hmrt) | First 25 hours ($ / MW-hmrt) | Second 25 hours ($ / MW-hmrt) | First 25 hours ($ / MW-hmrt) | Second 25 hours ($ / MW-hmrt)
Summer – Winter | 39,000 | 19,500 | 50,310 | 25,155 | 71,943 | 35,972
Fall - Spring | 6,500 | - | 8,385 | - | 11,991 | -
Generation units ≤ 50 MW
Period | SE No. 31/20 | SE No. 440/21 | SE No. 238/22
First 25 hours ($ / MW-hmrt) | Second 25 hours ($ / MW-hmrt) | First 25 hours ($ / MW-hmrt) | Second 25 hours ($ / MW-hmrt) | First 25 hours ($ / MW-hmrt) | Second 25 hours ($ / MW-hmrt)
Summer – Winter | 42,000 | 21,000 | 54,180 | 27,090 | 77,478 | 38,739
Fall – Spring | 7,000 | - | 9,030 | - | 12,913 | -
2.1.4.2 Remuneration for generated and operated energy In the case of thermal power generators, a remuneration was set for generated energy, depending on the type of fuel used, and for operated energy, as shown below:
Generated and operated energy termal units remuneration |  |  |  |
Remuneration | SE No. 31/20 ($ / MWh) | SE No. 440/21 ($ / MWh) | SE No. 238/22 ($ / MWh) | SE No. 826/22 ($ / MWh)
Generated energy | Between 240 and 420 | Between 310 and 542 | Between 403 and 705 | Between 585 and 1,023
Operated energy | 84 | 108 | 154 | 204
It is worth highlighting that if the thermal generation unit operates outside its optimal dispatch, the remuneration for generated energy will be recognised at 60% of the installed net capacity, irrespective of the energy delivered by the unit. In the case of hydroelectric plants, the following prices were established for generated and operated energy, irrespective of scale:
Generated and operated energy hydroelectic units remuneration |  |  |  |
Remuneration | SE No. 31/20 ($ / MWh) | SE No. 440/21 ($ / MWh) | SE No. 238/22 ($ / MWh) | SE No. 826/22 ($ / MWh)
Generated energy | 210 | 271 | 388 | 512
Operated energy | 84 | 108 | 154 | 204
The remuneration for operated energy should correspond with the grid’s optimal dispatch; however, the current resolution does not indicate which would be the consequence otherwise. In the case of pumping hydroelectric power plants, both the generated energy and that used for pumping are considered. Besides, if it works as a synchronous condenser, 60 $/MVAr, and 77 $/MVAr, 110 $/MVAr and 145 $/MVAr are recognised under SE Resolution No. 31/20, and No. 440/21, No. 238/22 and No. 826/22, respectively, for the megavolt-amperes exchanged with the grid when required, in addition to the prices for operated energy. As from November 2022, a differentiated remuneration scheme applicable to thermal and hydroelectric generators for generated energy at peak hours, was established with a remuneration equivalent to twice the value of the generated energy’s current price at peak hours (18:00 to 23:00) every day in the months of December, January, February, June, July and August, and to one time that value for the same hours in the months of March, April, May, September, October and November. As regards energy generated from unconventional sources, a single remuneration value was set irrespective of the source used:
Unconventional sources remuneration |  |  |  |
Remuneration | SE No. 31/20 ($ / MWh) | SE No. 440/21 ($ / MWh) | SE No. 238/22 ($ / MWh) | SE No. 826/22 ($ / MWh)
Generated energy | 1,680 | 2,167 | 3,099 | 3,719
Energy generated before commissioning by the Agency in Charge of Dispatch, will be remunerated at 50% of the above-mentioned remuneration. 2.1.4.3 Transitory additional remuneration On November 2, 2021, SE Resolution No. 1,037/21 provided as follows: (i) the creation of an exports account in the WEM’s stabilization fund for the accumulation of income from electricity export transactions conducted by CAMMESA, as from the economic transactions for the month of September 2021, for the financing of energy infrastructure works; and (ii) the transitory recognition of an additional remuneration to the one established by SE Resolution No. 440/21 for the economic transactions comprised between September 1, 2021 and February 28, 2022. On November 9, 2021, the SE, through Note NO-2021-108163338-APN-SE#ME, instructed CAMMESA to assume that covered generators have a 70% utilization factor, therefore, 100% of the power capacity remuneration would be paid, and added an amount of $ 1,000/MWh for exported energy, which will be distributed proportionately to the energy generated monthly by each generator. SE Resolution No. 238/22 canceled the detailed additional and transitory remuneration from the February 2022 economic transaction. 2.1.4.4 Suspension of contracts within the MAT The suspension of contracts within the MAT (excluding those derived from a differential remuneration scheme) provided for by SE Resolution No. 95/13 remains in effect. 2.1.5 Fuel supply for thermal power plants On December 27, 2019, the Ministry of Productive Development Resolution No. 12/19, restored the centralized scheme in CAMMESA for the supply of fuels for generation purposes (except for generators under the Energy Plus regime and with Wholesale Power Purchase Agreements under Resolution SE No. 287/17). In December 2020, on account of the implementation of the GasAr Plan (see Note 2.2.4.1.2), SE Resolution No. 354/20 was passed, which established a new dispatch order for generation units based on the fuel supplied for their operation under a centralized dispatch scheme. SE Resolution No. 354/20 established the gas volumes CAMMESA should prioritize in the electricity dispatch. In this sense, firm volumes to be used by CAMMESA were defined, including: i) volumes corresponding to contracts entered into by CAMMESA with producers acceding to the GasAr Plan; ii) volumes corresponding to contracts executed by adherent producers with generators acceding to the centralized dispatch (these volumes will be discounted by the adherent producers from the applicable quota for which they should enter into contracts with CAMMESA under the GasAr Plan) and; iii) volumes to meet the Take or Pay (“TOP”) obligations under the supply agreement entered into between IEASA and Yacimientos Petrolíferos Fiscales Bolivianos (“YPFB”). Besides, an electricity dispatch priority scheme was set based on the allocation of the natural gas quota taking into consideration the TOP obligations. To this effect, the following priorities were set (within each priority level, the order of agents is set based on the generator’s production cost):
| (i) | Dispatch Priority 1: Generators, Self-generators and/or Co-generators supplied with a natural gas quota under a TOP Bolivia condition assigned by IEASA. If a generator with a fuel stocking obligation optionally acquires from IEASA natural gas from Bolivia, this volume will be included in this quota.
| (ii) | Dispatch Priority 2: Generators, Self-generators and/or Co-generators supplied by CAMMESA with a natural gas quota from the centralized list of volumes up to the TOP of each contract.
| (iii) | Dispatch Priority 3: Generators, Self-generators and/or Co-generators supplied by CAMMESA with a natural gas quota from the centralized list of volumes for the Daily Maximum Amount (DMA) less those corresponding to the TOP of each contract.
| (iv) | Dispatch Priority 4: Generators, Self-generators and/or Co-generators supplied by CAMMESA with natural gas or LNG coming from other firm commitments undertaken by CAMMESA.
| (v) | Dispatch Priority 5: Generators, Self-generators and/or Co-generators supplied with a gas quota from the unassigned, spot natural gas contracts from any source, acquired by CAMMESA and/or the Generator, according to the supply source. In the case of a generator with its own fuel, the maximum amount to be acknowledged will be the corresponding reference prices.
As regards the costs associated with the supply of these fuels, it was established that the electricity demand will bear, among others, the regulated transportation costs, the cost of natural gas and the applicable TOP obligations. Generating agents that kept the possibility to purchase their fuel supply (agents under the Energy Plus regime or with Wholesale Purchase Agreements under Resolution SE No. 287/17) could opt in or out of CAMMESA’s unified dispatch, through the operating assignment of the contracted firm transportation and gas volumes, which impact the assigned priority order. Under such assignment, agents should waive all claims regarding the application of SE Resolution No. 354/20. In the specific case of generators with wholesale power purchase agreements under SE Resolution No. 287/17, it was provided that they would have the option of canceling the self-supply obligation and the resulting recognition of its associated costs, having to maintain the respective transportation capacity for its management in the centralized dispatch. The Company assigned the firm transportation and gas volumes committed to supplying Genelba Plus’ CC and Energy Plus contracts, setting certain guidelines for calculating fuel costs to support its Energy Plus contracts. In the case of the supply to Genelba Plus’ CC, the assignment will remain effective during the life of the GasAr Plan, and it may be revoked by the generator with a minimum advance notice of 30 business days. Within this framework, the parties agreed to enter into an addendum to the Wholesale Power Purchase Agreement to establish the modifications regarding this new supply scheme, which execution is pending as of the issuance of these Consolidated Financial Statements.
| 2.2 | Oil and gas
2.2.1 Argentine Hydrocarbons Law On October 29, 2014, the National Congress enacted Law No. 27,007 amending Hydrocarbons Law No. 17,319 (enacted in 1967), which empowers the Government to grant exploration permits and concessions to the private sector. Additionally:
| (i) | Sets the terms for exploration permits:
| - | Conventional exploration: the basic term is divided into two periods of up to three years each, plus an optional extension of up to five years;
| - | Unconventional exploration: the basic term is divided into two periods of four years each, plus an optional extension of up to five years; and
| - | Continental shelf and off-shore exploitation: the basic term is divided into two periods of three years each, plus an optional extension of one year each.
| (ii) | Sets the terms for exploitation concessions, extensible for 10-year terms:
| - | Conventional exploitation concession: 25 years;
| - | Unconventional exploitation concession: 35 years; and
| - | Continental shelf and off-shore exploitation concession: 30 years.
| (iii) | Sets transportation concessions will be granted for the same term than that granted for the originating exploitation concession.
| (iv) | Sets prices for payments of exploration and exploitation levy and empowers the enforcement authority to establish the payment of extension and exploitation bonds.
| (v) | Establishes a 12% royalty payable by the exploitation concessionaire to the grantor on the proceeds derived from liquid hydrocarbons extracted at wellhead and the production of natural gas. In the case of extension, additional royalties for up to 3% over the applicable royalties at the time of the first extension, up to a total of 18%, will be paid for the following extensions.
| (vi) | Provides for two types of non-binding commitments between the National Government and the Provinces aiming to establish a uniform environmental legislation and to adopt a uniform tax treatment to encourage hydrocarbon activities.
| (vii) | Restricts the National Government and the Provinces from reserving new areas in the future in favor of public or mixed companies or entities, irrespective of their legal form.
On its part, the Ministry of Energy and Natural Resources of the Province of Neuquén established certain parameters for the granting of Hydrocarbons Unconventional Exploitations Concessions (“CENCH”) in this province, instrumented through Resolution No. 53/20 dated July 1, 2020 and Resolution No. 142/21 dated November 24, 2021, and later ratified by Provincial Executive Order No. 2,183/21 in December 2021. Companies may request a CENCH based on a development project that will include a pilot plan for a term of up to five years to demonstrate its technical and economic feasibility. Furthermore, if companies request the inclusion in the CENCH of a surface larger than that assigned to the approved pilot plan, the payment of a block extension bond should be included, which value will be associated with the resources expected to be recovered in the extended block, considering the basin’s average price over the last two years. Besides, while the CENCH is in effect, companies should submit continuous development plans and investment commitments, updated annually. 2.2.2 Hydrocarbon exploration and exploitation levy Law No. 27,007 set the levy values per km2 or fraction to be paid annually and in advance by the permit holder. Exploitation permits will amount to $ 4,500 and exploration permits, to $ 250 in the first period, $ 1,000 in the second period of the basic term, and $ 17,500 during the first year of the extension (with a 25% annual cumulative increase). It is worth highlighting that up to 10% of the levy value payable in the second period of the basic term and the extension may be offset with actual investments per km2. On September 26, 2019, the Province of Neuquén, pursuant to Provincial Executive Order No. 2,032/19, published new levy values per km2 or fraction effective for this province from 2020. The exploitation levy was set at $ 22,410, and the exploration levy at $ 1,245 for the first period, $ 4,980 for the second period, $ 7,470 for the third period, and $ 87,150 for the extension period. From 2021, PEN Executive Order No. 771/20 set a maximum levy in pesos equivalent to a certain volume of oil at the average price for the semester before settlement, at BNA’s exchange rate effective on the last business day before payment. This scheme is applicable nationwide (including the Province of Neuquén, which acceded to it under Provincial Executive Order No. 1,656/20). Exploitation permits amount to 8.28 barrels and exploration permits to 0.46 barrels in the first period, 1.84 barrels in the second period of the basic term, and 32.22 barrels in the extension period. 2.2.3. Currency access for incremental oil and natural gas production systems and regional and national supplier’s employment, labor and development promotion system On May 28, 2022, PEN Executive Order No. 277/22 was published, which established currency access systems for the incremental production of oil (“RADPIP”) and natural gas (“RADPIGN”), as well as the regional and national supplier’s employment, labor and development promotion system (“RPEPNIH”). This executive order, later regulated by PEN Executive Order No. 484/22 dated August 12, 2022, mainly provided for eased access to the MLC for beneficiaries increasing their gas injection levels and/or oil production. Beneficiaries must meet the following requirements to access the RADPIP and the RADPIGN: (i) be registered with the SE’s oil companies registry; (ii) accede to the system; (iii) attain an incremental oil production or natural gas incremental injection levels; (iv) comply with the RPEPNIH; and (v) be an awardee and fulfill the obligations provided under natural gas production promotion or stimulus programs (exclusively for the RADPIGN). Beneficiaries under these systems may access the MLC to make principal and interest payments of commercial or financial liabilities abroad, including liabilities with non-resident affiliates, and to pay earnings and dividends for closed and audited balance sheets and/or the repatriation of direct investments by non-residents. This benefit may be transmitted to direct suppliers. Moreover, access to the MLC under this system will not be subject to BCRA’s prior authorization requirement in case exchange regulations so require. Currency access benefits for acceding the RADPIP and/or RADPIGN will be taken into consideration and timely discounted. Regarding the RPEPNIH, supplier development plans guaranteeing regional and national integration will be controlled. Moreover, a hiring scheme is contemplated granting preferences to regional and national goods and/or services suppliers. On January 16, 2023, SE Resolution No. 13/23 was published in the BO, which regulated the opt-in system and the procedure to obtain the currency access benefit created by PEN Executive Order No. 277/22. On February 8, 2023, the Company requested the opt-in to both aforementioned regimes and the benefits for the third and fourth quarters of 2022. 2.2.4 Gas Market 2.2.4.1 Natural Gas Production Promotion or Stimulus Programs 2.2.4.1.1 Argentine Natural Gas Production Promotion Plan (“GasAr Plan”) On November 16, 2020, Executive Order No. 892/20 was published in the BO, which approved the GasAr Plan to foster the development of the Argentine gas industry based on a bidding mechanism, and instructed the SE to instrument such plan and to set the applicable complementary and clarifying rules. On November 23, 2020, the SE, through Resolution No. 317/20, launched the “National Public Call for Tenders for the Argentine Natural Gas Production Promotion Plan – 2020-2024 supply and demand scheme” for the award of a volume of 70 million m3 of natural gas per calendar year (CAMMESA plus distributors), which may be modified by the SE to guarantee an optimal domestic supply. The contract samples stipulated a Deliver or Pay (“DOP”) obligation of 100% per day for producers and a Take or Pay (“TOP”) obligation of 75% per month for CAMMESA and per quarter for distributors. Regarding the payment of contracts with distributors, the Federal Government will bear the monthly difference between the price tendered and that resulting from the tariff schemes through a subsidy payable directly to producers. Under Law No. 27,591, payment of this subsidy is secured by Tax Credit Certificates, which were regulated by SE Resolution No. 125/21 and AFIP General Resolution No. 4,939/21. Additionally, to access the GasAr Plan producers submitted a plan of investments necessary to maintain the committed production and a national added-value commitment providing for the development of direct local, regional and national suppliers. On December 15, 2020, Resolution No. 391/20 was published in the BO, awarding the natural gas volumes tendered under GasAr Plan, Round 1. In this sense, out of a total natural gas base volume of 67.42 million m3/day to be purchased, in terms of tendered volume, the Company ranked third in the Neuquina Basin, with an awarded base volume of 4.9 million m3/day at an annual average price of US$ 3.60/MBTU for a term of four years effective as from January 1, 2021. Additionally, the Company has been one of the three producers tendering an additional volume for the winter period, with the award of 1 million m3/day at US$ 4.68/MBTU, a volume deemed indispensable to accompany the high seasonality of the Argentine demand, reducing gas imports, the consumption of alternative fuels, and the use of foreign-currency reserves. On March 9, 2021 Resolution No. 169/21 was published in the BO, which awarded natural gas volumes offered under the GasAr Plan, Round 2 Tender. In this sense, the Company was awarded a volume of 0.70 million m3/day, 0.90 million m3/day and 1 million m3/day for the months of June, July and August-September 2021, respectively, and 0.86 million m3/day to meet the winter peak demand for the years 2022 through 2024, at a price of US$ 4.68/MBTU. Under Resolution No. 984/21 dated October 19, 2021, the SE called for Round 3 under GasAr Plan for 2022 through 2024 inclusive, with injection starting in May 2022. The resolution determined that the cap price for tenders is the maximum price tendered under Round 1. The Company took part in this call, tendering 2 million m3/day for the Neuquina basin at a price of US$ 3.347/MBTU; on November 11, 2021, the SE issued Resolution No. 1,091/21, awarding the tendered volumes and prices. 2.2.4.1.2 2023-2028 Plan to Reinsure and Encourage Federal Hydrocarbon Production, Domestic Self-Supply, Exports, Imports Substitution, and the Expansion of the Transportation System for all the Country’s Hydrocarbon Basins (“Reinsurance Plan”) On November 3, 2022, Executive Order No. 730/22 was published in the BO, which amended the GasAr Plan’s scheme approved by Executive Order No. 892/20. The Reinsurance Plan establishes a new term for the system until December 31, 2028, with the following main objectives: (i) consolidating a new 70 MMm3/d flat block (volumes awarded under GasAr Plan’s Round 1 and 3), excluding winter peaks; and (ii) developing the demand for the incremental volumes to be evacuated using the new transportation capacity following the construction of the Néstor Kirchner Gas Pipeline (TransportAr Program, SE Resolution No. 67/22). Consequently, on November 14, 2022, SE Resolution No. 770/22 was published in the BO, calling for Tender Rounds 4 for the Neuquina Basin, and 5, for the Del Golfo and Austral Basins. For the Neuquina Basin, the following calls were made: (i) Round 4.1: for the extension of the commitments undertaken under Rounds 1 and 3 of the GasAr Plan for 4 additional years, from January 1, 2025 to December 31, 2028, for the same volumes, and with prices equal to or lower than the timely awarded price; and (ii) Round 4.2: for the award of the following incremental volumes: (a) Flat Gas: 11 MMm3/day from July 1, 2023 to December 31, 2028, and 3 MMm3/day from January 1, 2024 to December 31, 2028, with prices not exceeding US$ 4 MBTU; and (b) Peak Gas: 7 MMm3/day from May 1 to September 30, for each of the 2024-2028 and 2025-2028 periods, with prices equal to or lower than US$ 6.9 MBTU and an applicable 1.3 adjustment factor. The Company participated in Round 4.1, seeking to extend commitments under GasAr Plan’s Rounds 1 and 3 until December 2028 and keeping the originally tendered prices of US$ 3.6 MBTU and US$ 3.347 MBTU, respectively. Moreover, it submitted the following tenders under Round 4.2: (i) Flat Gas: 4.8 million m3/day at a price of US$ 3.485 MBTU from July 1, 2023 to December 31, 2028; (ii) Peak Gas: 3 million m3/day at a price of US$ 5.190 MBTU for the 2024-2028 period and 1.9 million m3/day at US$ 4.770 MBTU for the 2025-2028 period. On December 22, 2022, through SE Resolution No. 860/22, the Company was awarded the extension of the commitments for Round 4.1 and a 4.8 million m3/day demand associated with flat gas under Round 4.2. The awards granted to the Company and the contracts executed represent a production commitment of 15.7 million m3/day for winter periods and 13.8 million m3/day for summer periods in 2023-2024. Compared to 2022, this commitment represents a 44% increase in winter production, the period with the largest gas supply needs in the country. As from 2025, the commitment under the Reinsurance Plan will amount to 13.8 million m3/day. Based on the gas demand curve projected by the SE, the Company will enter into new contracts with CAMMESA, IEASA and distributors. 2.2.4.2 Natural gas for the residential segment and CNG On May 27, 2022, SE Resolution No. 403/22 provided for an update of new natural gas PIST prices under existing contracts executed within the framework of GasAr Plan’s promotion scheme, reducing the subsidy payable by the Federal Government from June 1, 2022. Additionally, in the months of February, June and August 2022, public hearings were held to analyze the Plan Gas.Ar portion of the natural gas PIST price to be borne by the Federal Government. It is worth highlighting that SE Resolution No. 610/22 determined a gradual increase in the PIST price distributors will pay for unsubsidized residential consumptions, keeping the subsidized price for the remaining users. On January 10, 2023, SE Resolution No. 6/23 was published, establishing updates of natural gas PIST prices for contracts executed under the GasAr Plan and the Reinsurance Plan based on the different types of users. 2.2.4.3 Acquisition of Natural Gas for Generation From December 30, 2019, CAMMESA’s centralization scheme for the supply of fuels for generation was restored (except for generators with Energy Plus and SE Res. No. 287/17 contracts). Since then, CAMMESA has launched successive calls for tenders to cover its monthly consumption. Moreover, from 2021, most gas supplies to CAMMESA are channeled through GasAr Plan, for the volumes committed under this program over an initial term of 4 years. In addition to GasAr Plan, in 2021 CAMMESA continued calling for tenders on a monthly basis, at a maximum price of US$ 2.3/MBTU until April and US$ 3.5 until August, on an interruptible basis for GasAr Plan awardees and under a 30% DOP clause for the rest. However, from September 2021 these calls were declared unawarded. On the other hand, since mid-July 2021 CAMMESA launched biweekly calls for tenders by GasAr Plan awardees that may offer surplus volumes, with a maximum price equivalent to that awarded in the plan’s Round 1. In 2022, an average of 451 million m3/day were awarded at a price of US$ 3.5/MBTU (of which 276 million m3/day correspond to the Neuquina Basin). 2.2.4.4 Natural Gas Exports On April 27, 2021, SE Resolution No. 360/21 regulated the new procedure for the authorization of natural gas exports. This resolution contemplates exports on a firm and preferential basis for GasAr Plan’s awardees, and sets a minimum sale price equivalent to the summer price awarded in Round 1. In this manner, the Company, as an awardee under GasAr Plan, may make firm exports during the summer period, extendable to the winter period when there is an oversupply in a specific basin and with the prior approval of the applicable authority. In May and December 2021, Pampa was granted permits to export gas to Chile on a firm basis for a maximum volume of 1.5 million m3/day and 1.22 million m3/day for the October 2021 – April 2022 and January – April 2022 periods, respectively. Besides, between September and December 2021, new interruptible permits to Chile, Brazil, and Uruguay were added, with expirations between November 2022 and December 2024. Under GasAr Plan, in August 2022 the Company was cleared to export gas to Chile on a firm basis for a maximum volume of 1,492 MMm3/d for the October 2022 – April 2023 period. On November 17, 2022, SE Resolution No. 774/22, which supersedes SE Resolution No. 360/21, was published in the BO. This resolution establishes a new proceeding delimiting four export areas: the Neuquina Basin and the Austral Basin with summer quotas (October 2023-April 2024 period) of 9 MMm3/day and 2 MMm3/day, respectively, and the Noroeste Basin and other areas with no quota definition. The distribution of firm summer quotas among producers is made considering (i) the share of the producer’s volume in the basin’s total volume, and (ii) the highest discount in the weighted-average price discount per volume against the basin’s incremental volume. The minimum reference price is set at the higher of the Brent quotation percentage determined by the SE and the average price awarded, adjusted by the seasonal index, with the authorization to withdraw volumes from the contracts executed under GasAr Plan and/or the Reinsurance Plan with CAMMESA and/or ENARSA. Additionally, for the Neuquina Basin, firm exports for 3 million m3/day will be authorized for the May-June 2023 period, to be apportioned among producers awarded under Round 4.2 - Flat Gas for the July 1, 2023-December 31, 2028 period. It is worth highlighting that a natural gas export duty has been in effect since May 2020. PEN Executive Order No. 488/20, issued on May 19, 2020, established an export duty exemption as long as the international Brent price was equal to or below US$45/bbl. The rate would rise gradually in line with the international reference price until reaching 8%, the cap to be recognized when Brent equals or exceeds US$60/bbl. Since February 2021, the rate has remained at 8%. 2.2.4.5 “TransportAr National Production” Pipelines System Program On February 9, 2022, SE Resolution No. 67/22 was published in the BO declaring the construction of “President Néstor Kirchner Pipeline” of national public interest. This pipeline will transport natural gas through the Province of Neuquén, the Province of Buenos Aires, and the Province of Santa Fe. Moreover, it created the TransportAr Production Gas Pipelines System Program to execute the works necessary to expand the system’s transportation capacity including a list of pipeline works to be executed by IEASA or through third parties to promote development, production growth, and natural gas self-supply, among other objectives. On August 10, 2022, Argentine authorities signed contracts for the Stage 1 Néstor Kirchner Gas Pipeline construction, that will connect the cities of Tratayén (Neuquén) with Salliqueló (Buenos Aires) and will cross the provinces of Río Negro and La Pampa. As of the issuance of these Consolidated Financial Statements, the aforementioned construction is underway, and commissioning is expected for June 2023. Later, PEN Executive Order No. 76/22, published on February 14, 2022, granted IEASA a 35-year transportation concession of President Néstor Kirchner pipeline under Law No. 17,319 and the power to contract, plan, execute and call for tenders for the construction of the infrastructure works under the Program. IEASA may enter into transportation capacity freely-negotiated agreements with producers and/or carriers to construct or expand all or part of the pipeline. This transportation capacity will not be covered by tariffs approved by ENARGAS, which will apply to the remaining transportation capacity not committed under these agreements. This executive order grants YPF priority to hire the capacity that can be freely negotiated by IEASA. Moreover, IEASA may fully or partially assign ownership of its concession to YPF. Besides, the “Argentine Gas Development Fund” administrative and financial trust was created, with IEASA as trustor and beneficiary, to finance works under the program, including the repayment of principal and interest services of the trust securities to be issued thereunder. The trust estate administrator and trustee will be Banco de Inversión y Comercio Exterior S.A. 2.2.5 Oil market 2.2.5.1 Crude oil price As of this date, there is no reference price for the sale of crude oil in the domestic market. However, considering pump prices for fuels, local refining companies are validating prices below the export parity. Just as with natural gas exports, a crude oil export duty has been in effect since May 2020. PEN Executive Order No. 488/20, issued on May 19, 2020, provided for an export duty exemption as long as the international Brent price was equal to or below US$ 45/bbl, rising gradually as the international reference price increased until reaching 8%, the cap to be recognised when the reference price equals or exceeds US$ 60/bbl. Since February 2021, the rate has remained at 8%. 2.2.5.2 Oil transportation In fiscal year 2022, Oldelval, as holder of the national liquid hydrocarbons transportation concession, launched a call for tenders to award and hire the firm transportation service for the Allen - Puerto Rosales oil pipeline tranche for a capacity of up to 50,000 m3/day. This volume has been fully awarded, and the necessary execution contracts have been entered into, effective until the termination of the transportation concession term in 2037. Pampa was awarded 1,002 m3/day. Under Oldelval’s call for tenders, the company Oiltanking Ebytem launched a call to increase the oil dispatch capacity for up to 50,000 m3/day and the storage capacity for up to 300,000 m3. These expansions will be allocated exclusively to oil exports. Pampa was awarded a 1,002 m3/day dispatch capacity and oil storage capacity for 6,008 m3.
| 2.3 | Gas Transportation
2.3.1 TGS’s Tariff situation On March 30, 2017, TGS executed the 2017 Integral Agreement which was ratified on March 27, 2018, through PEN Executive Order No. 250/18. This executive order represents the conclusion of the RTI process and terminates all transitional agreements celebrated by TGS. The 2017 Integral Agreement set the guidelines for the provision of the natural gas transportation service until the end of the license, among these guidelines approved: (i) a tariff increase was granted in installments for TGS as from April 1, 2017; (ii) a Five-Year Investment Plan to be executed by TGS between April 2017 and March, 2022; and (iii) a non-automatic six-month adjustment mechanism for the natural gas transportation tariff and the investment commitments considering IPIM published by INDEC subject to ENARGAS’ approval. In the public hearing held on September 4, 2018, in which TGS requested, based on the variation of the IPIM recorded for the period February - August 2018, a tariff increase of approximately 30%. Considering the hearing, on September 27, 2018, ENARGAS issued Resolution No. 265/18 which determined a 19.7% tariff increase effective as of October 1, 2018. This increase was determined by ENARGAS based on the simple average of the IPIM, the construction cost index for the period February and August 2018 and the Salary Variation Index between December 2017 and June 2018. ENARGAS supported the determination of the aforementioned tariff increase in the provisions of Resolution No. 4,362/17, which, among other issues, provided that under certain circumstances and macroeconomic conditions, such as the significant devaluation occurred after April 2018, ENARGAS may use other indexes than the IPIM to determine the tariff increase. TGS notified ENARGAS of its disagreement with respect to the methodology for calculating the semi-annual adjustment. On March 29, 2019, ENARGAS issued Resolution No. 192/19 approved, effective as from April 1, 2019, a 26% increase in tariff schemes applicable to the natural gas transportation utility by TGS current as of March 31, 2019. In accordance with current regulations, ENARGAS considered the evolution of the IPIM update index between the months of August 2018 and February 2019 to define six-monthly adjustments to TGS’ tariffs. As regards the semi-annual tariff update which should have become effective as from October 1, 2019, on September 3, 2019, the SE issued Resolution No. 521/19, later amended by Resolution No. 751/19, postponed its application until February 1, 2020. This deferral resulted in the revision and adjustment of the Five-Year Investment Plan execution, in the same proportion as the foregone income for TGS. On December 16, 2020, PEN Executive Order No. 1,020/20 was passed within the framework of the Solidarity Law. This executive order launched the renegotiation of the RTI concluded in 2018 within a term of 2 years. During this term, renegotiation agreements in force are suspended. On December 7, 2022, PEN Executive Order No. 815/22 was published in the BO, extending the renegotiation term for 12 months until December 16, 2023. Additionally, the Solidarity Law, PEN Executive Order No. 1,020/20 and PEN Executive Order No. 1815/22 provide for the administrative intervention of the ENARGAS. The public hearing called by ENARGAS to discuss the RTT pursuant to the provisions of PEN Executive Order No. 1,020/20 took place on March 16, 2021. In this respect, TGS, without waiving the whole of its percentage share of tariff recomposition, alternatively submitted in the hearing its tariff increase proposal, assessed at 58.6% as from April 1, 2021. This increase was assessed based on the financial needs to meet operating and financial costs, capital expenditures and taxes, which were calculated taking into consideration the evolution of the inflation rate over a 12-month period as from its beginning. The requested increase only contemplated the funds necessary to meet its obligations as licensee. Additionally, TGS denied and dismissed the arguments raised in the public hearing, which considered that the current natural gas transportation tariff is not fair or reasonable given the alleged existence of serious flaws in the administrative acts resulting from the proceedings for the last RTI established for TGS. On April 28, 2021, ENARGAS submitted to TGS the 2021 Transitional Agreement (“RTT 2021”), which: (i) does not grant a transitory tariff update, keeping unchanged the tariff schemes approved by ENARGAS in April 2019; (ii) provides that, as from May 2021 and until the Final Renegotiation Agreement enters into effect, ENARGAS will recalculate the transportation tariffs effective at the time, with validity as from April 1, 2022.; (iii) does not establish a mandatory investment plan; and (iv) establishes the prohibition to distribute dividends, early cancel financial and commercial debts taken on with shareholders, acquire other companies, or grant loans. On April 30, 2021 and through a note sent to this body, TGS expressed that, given the context in which it develops its activities and the proposed terms and conditions, it is not feasible for TGS to enter into the RTT 2021. On June 2, 2021, ENARGAS issued Resolution No. 149/21 approving an RTT 2021 for TGS effective as from that date. Moreover, the National Ministry of Economy and ENARGAS issued Joint Resolution No. 1/21 approving the proceedings under the renegotiation process developed by ENARGAS pursuant to PEN Executive Order No. 1,020/20, stating that it was not feasible to reach an agreement on a transitional tariff update. Given this situation, in July 2021, TGS filed motions for reconsideration, subsidiarity filing a hierarchical appeal, before the PEN, the National Ministry of Economy and ENARGAS according to the respective jurisdictions of each of these bodies in the passing of the regulations associated with Resolution No. 149/21, requesting the declaration of nullity of the RTT 2021 and the reinstatement of the RTI. The challenges are based on: (i) the illegality of Executive Order No. 1,020/20, as it does not observe the delegation lines provided for by Act No. 27,541 and, as it does not meet the requirements established by the Constitution for the dictation of this regulation; (ii) the extension of the emergency period beyond that established by the Congress; (iii) the tariff renegotiation under Act No. 24,076 is not performed; (iv) the disregard for the principle of fair and reasonable tariffs, and the rights acquired by TGS under the license, the Contractual Adjustment Memorandum of Understanding and the RTI; and (v) the suspension of the RTI for reasons of public interest, which merits the recognition of the compensations provided for by both the Administrative Procedures Act and the License Basic Rules. In turn, the restrictions on the management and administration of TGS have been challenged for lacking legal justification, as the emergency declared by Act No. 27,541 only empowered the PEN to renegotiate the RTI, but not the License. The challenges and the request for reinstatement of the RTI have been filed notwithstanding TGS’s right to the payment of the compensations it is entitled to on account of the breach of the RTI as from April 2019. On November 15, 2021, TGS filed a Prior Administrative Claim before ENARGAS and the Ministry of Economy. This presentation seeks to request compensation due to TGS for the non-application of the semi-annual adjustment methodology set by the RTI and approved by Resolution 4,362 between October 1, 2019 and June 1, 2021. Moreover, TGS seeks compensation for the damages sustained by the freeze resulting from the failure to apply the semi-annual adjustment methodology set by the RTI for this period. On January 19, 2022, a new public hearing was held within the framework of ENARGAS Resolution No. 518/21 to address the transition tariff update under PEN Executive Order No. 1020/20. In this hearing, aiming to reach a final agreement and restore the economic and financial equation, TGS requested a transition tariff adjustment in two stages for 2022 for a total of 106%, given the evolution of operating costs and the main macroeconomic indicators. Later, on February 1, 2022, TGS received from ENARGAS the proposed Renegotiation Transition Agreement (the “RTT 2022”), which was approved by TGS’s Board of Directors on February 2, 2022, and by the applicable governmental bodies on February 18, 2022. The RTT 2022 included certain terms similar to the RTT 2021, with the specific provision that it granted TGS a 60% tariff increase effective from March 1, 2022. The RTT 2022 was ratified through PEN Executive Order No. 91/22, effective from February 23, 2022. On February 25, 2022, ENARGAS Resolution No. 60/22 was published in the BO, launching the tariff schemes contemplated in the RTT 2022. It is worth highlighting that, as provided in the RTT 2022, TGS undertook not to initiate new claims, remedies, lawsuits, or any kind of actions; and/or to suspend, keep suspended or extend the suspension of all claims and remedies associated in any way with the current RTI renegotiation, Law No. 27,541, Decrees No. 278/20 and No. 1,020/20. On December 7, 2022, ENARGAS issued Resolution No. 523/22 calling for a public hearing, to be held on January 4, 2023, to consider the transitional tariff update for the natural gas transportation utility. As of the issuance of these Consolidated Financial Statements, TGS is working jointly with ENARGAS to conduct the RTI process that will allow the company to receive a fair and reasonable tariff in line with the provided natural gas transportation utility service. 2.3.2 Regulatory framework of the segment of Production and Commercialization of Liquids 2.3.2.1 Domestic market The production and commercialization of liquids segment is not subject to regulation by ENARGAS. However, over recent years, the Argentine Government enacted regulations which significantly impacted it. GLP domestic sales prices are impacted by the provisions of Law No. 26,020 "Regime of the industry and commercialization of liquefied petroleum gas" and the Argentine Government through the public office in charge, that set forth LPG minimum volumes to be sold in the local market in order to guarantee domestic supply. In this context, TGS sells the production of propane and butane to fractionators at prices determined semiannually. On March 30, 2015, the PEN issued Decree No. 470/15, regulated by SE Resolution No. 49/15, which created the “Household Plan” and sets a maximum reference price for the members of the commercialization chain in order to guarantee the supply to low-income residential user, by committing the GLP producers to supply at a fixed price with a quota assigned to each producer. Additionally, payment of compensation to the Household Plan participating producers was established. TGS has filed various administrative and judicial claims challenging the general regulations of the program, as well as the administrative acts that determine the volumes of butane that must be sold in the domestic market, in order to safeguard its economic-financial situation and thus, preventing that this situation does not extend over time. In addition, TGS is a party of the Propane Gas Supply Agreement for Induced Propane Gas Distribution Networks ("Propane for Networks Agreement") entered into with the Argentine Government and propane producers by which it undertakes to supply propane to induced propane gas distributors and sub- distributors through at a price lower than the market price. In compensation, TGS receives an economic compensation calculated as the difference between the sale price and the export parity determined by the SE. As it has been previously mentioned, participation in the Household Plan results in economic and financial damage to TGS, since under certain circumstances products would be sold at prices below their production costs. As of December 31, 2022, the Argentine Government owes TGS $ 3,768 million under these items. 2.3.2.2 Foreign market Executive Order No. 488/20 regulated the rate applicable to the export duties for certain gas and oil derivatives, including the products produced and exported by TGS, which ranges between 0% and 8% depending on the price of the “ICE Brent first line” barrel. If this price is below US$ 45, the rate is 0%. Instead, if the price equals or exceeds US$ 60, an 8% rate is paid, and the rate is variable if the price is between US$ 45 and US$ 60.
| 2.4 | Transmisión
2.4.1 Transener and Transba tariff situation On February 25, 2022, the ENRE communicated Resolutions No. 68/22 and 69/22 approving the new hourly remuneration values effective from February 1, 2022, establishing a 25% and 23% increase compared to the values effective from 2019 for Transener and Transba, respectively. Considering the difference between the presented financial and economic projections and the values finally approved by the ENRE, a motion to review the records and the respective preliminary challenges was submitted. Moreover, on March 15, 2022, the applicable motions for reconsideration against these resolutions were filed. Consequently, under Resolutions No. 147/22 and 148/22, on May 9, 2022 the ENRE partially upheld the filed motions and modified the hourly remuneration values effective from February 1, 2022, establishing a 67% and 69% increase over the values effective from August 2019 for Transener and Transba, respectively. Since August 2022, Transener and Transba filed notes and held meetings with the SE and the ENRE requesting an update to the transitional tariffs effective from September 2022, chargeable against the increase to be assessed for 2023. To this effect, the 2023 economic and financial projection was presented with an explanatory document and a detail of the projected investment plan. Moreover, a presentation was made to CAMMESA’s Board of Directors to put the criticality of the transportation sector on record. Under Resolution No. 539/2022, on October 20, 2022 the ENRE called for a public hearing on November 30, 2022 to inform of and gather feedback on the electricity transmission utility concessionaires’ proposals towards a transitional tariff update under the RTI Renegotiation Process before defining the tariffs applicable by the concessionaires. Furthermore, on December 6, 2022, PEN Executive Order No. 815/22 extended for one-year term PEN Executive Order No. 1,020/20 published on December 17, 2020, through which initiated RTI renegotiation within up to 2 years from its publication. Later, on December 29, 2022, aiming to preserve in 2023 the purchasing power of the revenues established in Resolutions No. 147/22 and 148/22, the ENRE issued Resolutions No. 698/22 and 702/22 setting the hourly remuneration values effective from January 1, 2023, and establishing a 154.5% and 154.1% increase over the February 2022 values for Transener and Transba, respectively.
| 2.5 | Regulations on access to the MLC
In 2020, BCRA introduced measures with the purpose of regulating inflows and outflows in the MLC to maintain the exchange rate stability and protect international reserves in view of the high degree of uncertainty and volatility in the exchange rate, including restrictions associated with transactions with stock market assets by companies and the disposal of liquid foreign assets. To access the MLC in terms of expenditures without BCRA’s prior authorization, it is necessary to file an affidavit certifying that all foreign-currency holdings in the country are deposited in accounts with local financial institutions and that it no available liquid foreign assets are held for an amount equivalent to or higher than US$ 100,000. In case such liquid foreign assets exceed the amount of US$ 100,000, an additional affidavit could be submitted according to the applicable provisions. To such effects, the term “liquid foreign assets” will comprise, among others: holdings of foreign currency notes and coins, availability of gold in the form of good delivery bars or coins, sight deposits in foreign financial entities, holding of Argentine certificates of deposit (“CEDEAR”) and other investments allowing for the immediate availability of foreign currency (for example, investments in foreign public securities, funds in investment accounts deposited with investment managers located abroad, crypto assets, funds deposited in payment service providers’ accounts, etc.). On the other hand, the following will not be considered available liquid foreign assets: funds deposited abroad that may not be used by the customer as they are reserve or guarantee funds created under foreign debt contracts, or funds kept as collateral for foreign transactions with derivatives entered into abroad. Furthermore, in case access to the MLC has been requested, it is mandatory to enter and settle in the MLC, within a term of five business days after they become available, foreign funds originating from the collection of loans granted to third parties, the collection of time deposits or the sale of any kind of asset, in case the asset has been acquired, the deposit has been made or the loan has been granted after May 28, 2020. As regards transactions with stock market assets is established: (i) the presentation of an affidavit declaring that, on the date of access to the MLC and in the previous 90 calendar days, no domestic sales of securities to be settled in foreign currency, exchanges of securities issued by foreign active residents, transfers of securities to foreign depositary entities, local acquisitions of securities issued by non-residents and settled in pesos, acquisitions of CEDEAR representing foreign shares (from July 22, 2022), acquisitions of private debt securities issued in a foreign jurisdiction, or deliveries of funds in domestic currency or other domestic assets (except for foreign-currency funds deposited with local financial entities) to any natural or legal, resident or non-resident person, and whether or not affiliated, receiving as prior or subsequent consideration, whether directly or indirectly, on its own or through any affiliate, controlled or controlling entity, foreign assets, crypto-assets or securities deposited abroad and, lastly, the commitment not to perform any of the detailed transactions for 90 calendar days following the request for access to the MLC should be evidenced; and (ii) that security transactions concerted abroad and securities acquired abroad may not be settled in pesos in the country. Moreover, if the customer is a legal entity, as an additional requirement to access the MLC, it also provided for an additional affidavit stating: (a) details of the individuals or legal entities exercising a direct control relationship over the customer, according to BCRA’s regulations; and (b) that on the day access to the MLC is requested and in the previous 90 calendar days, no local-currency funds or other liquid domestic assets have been delivered in Argentina to any individual or legal entity exercising a direct control relationship over it, except for those directly associated with regular transactions for the acquisition of goods and/or services. The requirement stated in item (b) will be deemed duly met if the customer submits an affidavit regarding transactions with securities of each individual or legal entity pursuant to the current exchange regulations. BCRA’s prior authorization to access the MLC to cancel the principal of foreign financial debts with foreign affiliates is required up to and including December 31, 2023. Furthermore, the BCRA extended the obligation to submit a refinancing plan for certain debts and principal maturities scheduled until December 31, 2023, based on the following criteria: (i) access to the MLC for up to 40% of the principal amount, within the original term; and (ii) the refinancing of the principal balance, through new foreign indebtedness with an average life of 2 years. Within the framework of this refinancing process, access to the MLC is allowed for the early cancellation of principal, interest or debt swaps up to 45 calendar days before the maturity date, provided all requirements set forth by the regulation have been verified. On October 2022, the Integral Import Monitoring System (“SIMI”) and the Integral Foreign Payments Monitoring System (“SIMPES”) were replaced by the Argentine Republic’s Imports System (“SIRA”) and the Argentine Republic’s Imports and Foreign Service Payments System (“SIRASE”), respectively. Moreover, BCRA established that no more advance, sight, or deferred without clearance payments may be made through these new mechanisms, except for certain cases contemplated in the regulation. Regarding imports, BCRA’s prior authorization to access the MLC is required to make payments to import certain goods abroad or cancel the principal of debts originating from the import of goods by companies. Additionally, before executing payments for the import of goods, entities should verify that the affidavit requested from the customer is compatible with BCRA’s existing data. Additionally, the BCRA created a registry of foreign exchange information of goods exporters and importers as a requirement to access the MLC to perform forex outflow transactions, including swaps and arbitrations. The Company has been declared an obliged subject by the BCRA; it has completed its enrollment in this registry and is under a duty to report any change in the recorded information within 15 business days of its occurrence. Additionally, in October 2022, the BCRA introduced adjustment to foreign exchange regulations, establishing, among other provisions, access to the MLC for subjects obtaining certifications under currency access systems for the incremental production of oil and/or natural gas pursuant to PEN Executive Order No. 277/22 (see Note 2.2.3), for up to the amount of each certification, to be allocated to the payment of: (i) principal and interest of commercial or financial liabilities abroad, including liabilities with non-resident affiliates, (ii) earnings and dividends for closed and audited balance sheets; and/or (iii) the repatriation of direct investments by non-residents. RADPIP and/or RADPIGN beneficiaries should appoint a single domestic financial entity responsible for issuing such certifications and recording the amounts recognized by the SE and the applicable period. More information on Argentina’s foreign exchange regulations can be found at the Central Bank’s website: www.bcra.gov.ar.
| 2.6 | Tax regulations - Main tax reforms
Pursuant to Law No. 27,430, Law No. 27,541, Law No. 27,630, and Law No. 27,701 several modifications were introduced in the tax treatment, the key components of which are described below: 2.6.1 Income tax 2.6.1.1 Income tax rate Pursuant to Law No. 27,430, the income tax rate for Argentine companies would be gradually reduced from 35% to 30% for fiscal years beginning from January 1, 2018 to December 31, 2019, and to 25% for fiscal years beginning on or after January 1, 2020. However, Law No. 27,541 suspended the tax rate reduction planned for fiscal year 2020, keeping the rate at 30%. On June 16, 2021, Law No. 27,630 was published in the BO, which modified the income tax rate effective for fiscal years starting as from January 1, 2021 inclusive. This modification provides for the application of a tiered rate scheme and, if applicable, a fixed tax according to the accumulated net taxable income tier: (i) for accumulated net income of up to $ 5 million, it establishes a 25% rate; (ii) for accumulated net income between $ 5 and $ 50 million, it establishes a fixed tax of $1.25 million plus a 30% rate over the surplus of $ 5 million; and (iii) for accumulated net income above $ 50 million, it establishes a fixed tax of $ 14.75 million plus a 35% rate over the surplus of $50 million. The accumulated net income amount will be adjusted yearly, as from January 1, 2022, taking into consideration the annual CPI variation published by the INDEC. The effect of the changes on deferred tax corresponding to comparative periods pursuant to the above-mentioned tax reform was recognised, considering the effective rate expected to be applicable at deferred assets and liabilities realization year, in “Effect of tax rate change in the deferred tax” under “Income tax” of the Consolidated Statement of Comprehensive Income (Note 10.5). On August 16, 2022, AFIP’s General Resolution No. 5,248/22 was published in the BO, whereby the AFIP established a one-time income tax prepayment by taxpayers and responsible persons listed in Section 73 of Law No. 20,628, as amended, meeting the following parameters: (i) an assessed tax for the 2021 or 2022 tax period of at least $ 100 million, or (ii) taxable income, without deducting accumulated tax losses, of at least $ 300 million. As of issuance of these Consolidated Financial Statements, the Company and its subsidiaries paid an income tax prepayment for $ 1,863 million. 2.6.1.2 Tax on dividends Law No. 27,430 and modifications introduced by Law No. 27,541 and Law No. 27,630, established a 7% tax on dividends derived from earnings accrued during fiscal years beginning as from January 1, 2018, which be distributed by Argentine companies to individuals, undivided estates or beneficiaries residing abroad. Dividends resulting from benefits gained until the fiscal year prior to that beginning on January 1, 2018 will remain subject to the 35% withholding on the amount exceeding the untaxed distributable retained earnings (equalization tax’ transition period) for all beneficiaries. 2.6.1.3 Tax inflation adjustment Law No. 27,430 sets out the following rules for the application of the income tax inflation adjustment mechanism:
| (i) | a cost adjustment for goods acquired or investments made during fiscal years beginning after January 1, 2018 taking into consideration the percentage variations in the CPI published by the INDEC; and
| (ii) | the application of the adjustment provided for by Title VI of the Income Tax Law when variations in the above-mentioned index exceed 100% over the 36 months preceding the closing of the fiscal period to be settled; alternatively, for the first, second and third fiscal year as from its effective date, this proceeding will apply in case the accumulated variation in such price index, calculated from the beginning of the first fiscal year to the closing of each fiscal year, are higher than 55%, 30% and 15% for the years 2018, 2019 and 2020, respectively.
Law No. 27,541 provided that, as regards the positive or negative fiscal inflation adjustment determined as a result of the application of the adjustment provided for by Title VI of the Income Tax Law corresponding to the first and second fiscal year starting as from January 1, 2019, one-sixth should be charged in that fiscal period and the remaining five sixths, in equal parts, in the five immediately following fiscal periods. On December 1, 2022, Law No. 27,701 was published in the BO, which established that taxpayers determining a positive inflation adjustment in the first and second fiscal year starting from January 1, 2022 (inclusive) may allocate one-third in that fiscal period and the remaining two-thirds, in equal parts, in the two immediately following fiscal periods. This computation only applies to subjects making investments in the purchase, construction, manufacture, production or final import of property, plant and equipment, except automobiles, during each of the two fiscal periods immediately following that in which the computation of the first third of the period in question exceeds or equals $ 30,000 million. Failure to comply with this requirement will result in the loss of this benefit. As of issuance of these Consolidated Financial Statements, this provision has not yet been regulated. The Company and its subsidiaries determine and disclose the impact of the tax inflation adjustment for each of the fiscal periods in which it is applicable (see Note 10.5). 2.6.2 Value-added tax A procedure is established for the reimbursement of tax credits originated in investments in property, plant and equipment which, after 6 months as from their assessment, have not been absorbed by tax debits generated by the activity.

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