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REGULATORY FRAMEWORK

12 Months Ended

Dec. 31, 2023

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 (SE Resolutions No. 1,281/06 and No. 281/17); ii) supply agreements with CAMMESA (SE Resolutions No. 220/07, No. 21/16, No. 287/17 and Renovar Programs) and iii) sales to the Spot market pursuant to the provisions applicable within the WEM administered by CAMMESA (SE Resolution No. 440/21 as from February 2021, SE Resolution No. 238/22 as from February 2022, SE Resolution No. 826/22 as from September 2022, SE Resolution No. 750/23 as from September 2023 and SE Resolution No. 869/23 as from September 2023). The Company’s generating units, held directly and through its subsidiaries and joint ventures, are detailed below:


In operation as of 12.31.2023:

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. 869/23
CTG	GUEMTV12	TV	≤100 MW	Resolution No. 869/23
CTG	GUEMTV13	TV	>100 MW	Resolution No. 869/23
Piquirenda	PIQIDI 01-10	MCI	30 MW	Resolution No. 869/23
CPB	BBLATV29	TV	>100 MW	Resolution No. 869/23
CPB	BBLATV30	TV	>100 MW	Resolution No. 869/23
CTIW	BBLMD01-06	MCI	100 MW	Resolution No. 21/16
CTLL	LDLATG01/TG02/TG03/TV01	CC	>150 MW	Resolution No. 59/23
CTLL	LDLATG04	TG	105 MW	Resolution No 220/07 (75%)
CTLL	LDLATG05	TG	105 MW	Resolution No. 21/16
CTLL	LDLMDI01	MCI	15 MW	Resolution No. 869/23
CTGEBA	GEBATG01/TG02/TV01	CC	>150 MW	Resolution No. 59/23
CTGEBA	GEBATG03	TG	169 MW	Energy Plus Res. No. 1,281/06
CTGEBA	GEBATG03/TG04/TV02	CC	400 MW	Resolution No. 287/17
Ecoenergía	CERITV01	TV	14 MW	Energy Plus Res. N° 1,281/06
CTPP	PILBD01-06	MCI	100 MW	Resolution No. 21/16
CTEB	EBARTG01 - TG02	TG	>50 MW	Resolution N° 59/23
CTEB	EBARTV01	TV	279 MW	Resolution No. 220/07
HIDISA	AGUA DEL TORO	HI	HI – Media 120<P≤300	Resolution No. 869/23
HIDISA	EL TIGRE	HR	Renewable ≤ 50	Resolution No. 869/23
HIDISA	LOS REYUNOS	HB	HB – Media 120<P≤300	Resolution No. 869/23
HINISA	NIHUIL I - II - III	HI	HI – Small 50<P≤120	Resolution No. 869/23
HPPL	PPLEHI	HI	HI – Media 120<P≤300	Resolution No. 869/23
PEPE II	PAMEEO	Wind	53 MW	MATER Res. No. 281/17
PEPE III	BAHIEO	Wind	53 MW	MATER Res. No. 281/17
PEPE IV	Ampliación BAHIEO	Wind	81 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.


In construction:

Generator	Tecnology	Capacity	Applicable regime
PEPE VI	Wind	140 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 GU 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 CTG, EcoEnergía and CTGEBA— 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, or are adjusted by CAMMESA’s price variation instead.

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 (or self-generation from renewable sources) through the individual purchase within the MATER.

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 to meet the GU’s demand that purchase energy to distribution utility companies.

Under this resolution, the Company, through its PEPE II, III and IV wind farms, sells energy for up to 187 MW. Additionally, the Company has started selling third-party generators’ renewable energy for a volume of 1.14 MW.

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 of monthly installments ranging between 500 and 1,500 US$/MW.

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.

SE Resolution No. 360/23 introduced several changes to the effective priority dispatch system. These modifications include the granting of a dispatch priority to renewable generation projects to be sold in the MATER that finance the corresponding transmission expansions and/or renewable energy generation projects with an associated demand larger than 10 MW.

Besides, it established a new referential dispatch priority system in corridors without full availability at every hour of the year. In this way, the dispatch priority will have an injection probability of 92% of the typical annual energy.

Moreover, it establishes that partially commissioned projects regarding the committed capacity will pay the dispatch priority charge exclusively for the difference between the assigned power capacity and that commissioned, provided the accumulated commissioned capacity is at least 50% of that assigned.

Finally, projects with commissioned power capacity lower than assigned power capacity will lose dispatch priority for uncommissioned power capacity.

Within the framework of this resolution, for the third quarter of 2023, the Company was awarded a 139,50 MW referential dispatch priority for the PEPE VI (Stages 1 and 2).

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 agreements 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 units remunerated under agreements for 79 MW and 280 MW, through CTLL thermal power plant and CTEB´s closed cycle, owned by CTB, respectively.

2.1.3.2 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 CTLL, CTIW and CTPP 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 CTGEBA thermal power plant, has entered into a wholesale power purchase agreement with CAMMESA for the sale of energy and power capacity for a total 400 MW, for a term of 15 years.

2.1.3.4 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 (“FODER”) destined, among other objectives, to the granting of loans and capital contributions for the financing of such projects.

Under the Renovar programs, the Company, has a supply contract in place with CAMMESA for a total of 99.75 MW for the PE Arauco.

2.1.3.5 Penalty system under MATER and Renovar contracts

On March 20, 2023, SE Resolution No. 165/23 was passed, which modified the penalty system applicable to MATER and Renovar projects, including projects awarded under the Renovar MiniRen Program, Round 3. Penalties for breaches in the committed supply of energy were incorporated into the system, to be discounted in 12 monthly and consecutive installments as from commercial commissioning, keeping the generator’s option to cancel the penalties in 48 monthly and consecutive installments with the application of a 1.7% EAR in U.S. dollars. To avoid affecting the projects’ minimum maintenance, a 20% discount cap for the monthly transaction was established for those generators opting into the 48-installment scheme. The balance following the application of this cap will be discounted in the first transaction in which the penalty is below the stated cap; if the number of installments is exceeded, the scheme will be maintained until the penalties’ full cancellation and, in case the contract term is exceeded, the payment scheme may be restructured, or the discount cap may be increased to 40% of the transaction.

Besides, SE Resolution No. 883/23 approved a penalty offsetting mechanism for supply agreements under the Renovar programs allowing to offset penalties with investments in new renewable power generation capacity. This possibility is contemplated for delay, deficiency and national component penalties.

2.1.3.6 TerCONF Call

On July 27, 2023, SE Resolution No. 621/23 launched the "TerCONF" call for the execution of reliable thermal generation supply agreements with CAMMESA allowing to incorporate new thermal supply and ensure the WEM's reliability and sustainability through: (i) supply to the SADI, and (ii) the substitution and modernization of Tierra del Fuego's power generation grid.

Regarding thermal generation for SADI's reliability and supply:

(i)

The call will consider any generation or co-generation technology, including associated transmission and/or fuels infrastructure works, to add reliable power capacity by installing new equipment or equipment with less than 15,000 hours of verified use;

(ii)

Agreements will not provide for fuel management responsibility, and a variable operation and maintenance remuneration is established based on the energy per fuel type;

(iii)

The agreement's price will contemplate the payment of the hired power capacity in US$/MW-month and the payment of the supplied energy;

(iv)

Projects should identify the point of delivery and the technical connection agreement with the transmission company; and

(v)

A supply maintenance guarantee and a payment scheme from the project's award to the contract execution date are established as a type of performance bond.

On September 26, 2023, 66 projects were submitted for a total of 7,112 MW power capacity. Pampa submitted a tender for the execution of CTGEBA II, with a 300 MW power capacity. It also tendered, through CTB, an 11 MW CC expansion. On November 24, 2023, pursuant to SE Resolution No. 961/23, both tenders were awarded, and the initial payments were executed according to the provisions of the call for tenders’ payment scheme. However, on December 28, 2023, the SE, through Note NO-2023-153876959-APN-SE#MEC, instructed CAMMESA to provisionally suspend the issuance of the commercial documentation corresponding to the payment of the tender guarantee and the monthly payment scheme. According to such note, SE is evaluating the exercise of the extension powers set forth in the bidding documents.

2.1.4 Remuneration at the Spot market

On May 19, 2021, SE Resolution No. 440/21 provided for a 29% increase in the values in pesos of the remuneration items based on technology and scale and the additional remuneration for the power capacity generated in the hours of maximum thermal demand of the month established in 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.

Subsequently, through SE Resolution No. 750/23 and SE Resolution No. 869/23, the remuneration values for spot generation were updated, providing for a 23% and 28% increase as from the September 2023 and November 2023 economic transactions, respectively.

The applicable remunerations based on technology and resolution are detailed below. The amounts reported correspond to the resolutions applicable as of December 31, 2021, 2022 and 2023.

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:


Technology / Scale	SE No. 440/21 ($ / MW-month)	SE No. 826/22 ($ / MW-month)	SE No. 869/23 ($ / MW-month)
Large CC Capacity > 150 MW	129,839	245,084	617,377
Large TV Capacity > 100 MW	185,180	349,546	880,520
Small TV Capacity ≤ 100 MW	221,364	417,847	1,052,573
Large GT Capacity > 50 MW	151,124	285,262	718,586

The remuneration for guaranteed power capacity to generators with availability commitments is:


Period	SE No. 440/21 ($ / MW-month)	SE No. 826/22 ($ / MW-month)	SE No. 869/23 ($ / MW-month)
Summer – Winter	464,400	876,601	2,208,195
Fall - Spring	348,300	657,451	1,656,146

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 was collected; if the utilization is between 30% and 70%, the power capacity payment ranged from 70% to 100%; and if the utilization factor was lower than 30%, 70% and 60% of the power capacity payment was collected until January 2020 and August 2021. Subsequently, the application of this factor was suspended in 2021 and finally abrogated from February 2022.

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:


Technology / Scale	SE No. 440/21 ($ / MW-month)	SE No. 826/22 ($ / MW-month)	SE No. 869/23 ($ / MW-mes)
Medium HI Capacity > 120 ≤ 300 MW	170,280	321,421	809,672
Small HI Capacity > 50 ≤ 120 MW	234,135	441,953	1,113,298
Medium Pumped HI Capacity > 120 ≤ 300 MW	170,280	321,421	809,672
Renewable HI Capacity ≤ 50 MW	383,130	723,196	1,821,760

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.

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:


Remuneration	SE No. 440/21 ($ / MWh)	SE No. 826/22 ($ / MWh)	SE No. 869/23 ($ / MWh)
Generated energy	Between 310 and 542	Between 585 and 1,023	Between 1,473 and 2,578
Operated energy	108	204	513

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:


Remuneration	SE No. 440/21 ($ / MWh)	SE No. 826/22 ($ / MWh)	SE No. 869/23 ($ / MWh)
Generated energy	271	512	1.288
Operated energy	108	204	513

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, 77 $/MVAr, 145 $/MVAr and 367 $/MVAr are recognised under SE Resolution No. 440/21, No. 238/22, No. 826/22 and 869/23, respectively, for the megavolt-amperes exchanged with the grid when required, in addition to the prices for operated energy.

As regards energy generated from unconventional sources, a single remuneration value was set irrespective of the source used:

Remuneration

SE No. 440/21

($ / MWh)

SE No. 826/22

($ / MWh)

SE No. 869/23

($ / MWh)

Generated energy

2,167

3,719

10,304

Energy generated before commissioning will be remunerated by the Agency in Charge of Dispatch at 50% of the above-mentioned remuneration.

2.1.4.3 Additional remuneration

For the February 2020-October 2022 period, an additional remuneration was set for the hours of maximum thermal demand (hmrt), corresponding to the 50 hours with the largest thermal generation dispatch in each month, divided into two blocks of 25 hours each, the following prices being applicable to the average capacity:

Thermal units:


Period	SE No. 440/21		SE No. 238/22
Period	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)
Summer – Winter	58,050	29,025	83,012	41,506
Fall - Spring	9,675	-	13,835	-

Hidroelectric units > 50 MW and ≤ 300 MW:

Period	SE No. 440/21		SE No. 238/22
Period	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)
Summer – Winter	50,310	25,155	71,943	35,972
Fall - Spring	8,385	-	11,991	-

Hidroelectric units ≤ 50 MW:

Period	SE No. 440/21		SE No. 238/22
Period	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)
Summer – Winter	54,180	27,090	77,478	38,739
Fall – Spring	9,030	-	12,913	-

As from November 2022, a differentiated remuneration scheme was established for energy generated during peak hours, applicable to thermal and hydroelectric generators, with a value equivalent to twice the value of the current price of energy generated during peak hours (6:00 p.m. to 11:00 p.m.) every day of the months of December, January, February, June, July and August, and one time such value for the same hours of the months of March, April, May, September, October and November.

2.1.4.4 Remuneration for combined cycles

SE Resolution No. 59/23 dated February 7, 2023 established a system combined cycles’ owners could opt-in by executing an availability and efficiency optimization agreement with CAMMESA. The agreement contemplates an availability commitment of 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 Company executed agreements with CAMMESA for its CTLL and GTGEBA power plants’ combined cycles. Additionally, CTB executed an agreement with CAMMESA for its open cycle’s GT units. In all cases, agreements are effective from March 1, 2023 to February 29, 2028.

2.1.4.5 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), 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 ENARSA 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 ENARSA. If a generator with a fuel stocking obligation optionally acquires from ENARSA 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 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.

2.1.6 New demand charges

Under Resolution No. 976/23, the SE established that, as from February 2024, CAMMESA should bill distribution agents and/or service providers of the WEM and Tierra del Fuego’s WEM system new charges that are directly transferred to GUDI customers’ bills.

The additional charges comprise: (i) a stabilized charge for the price of energy and (ii) a complementary power adjustment, seeking to bring GUDI costs in line with GUME and GUMA costs.

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 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 for exploitation and exploration permits, payable annually and in advance by the permit holder. 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 as from 2020.

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.

Through notes issued in August and September 2023, the Undersecretariat of Hydrocarbons granted the Company the certificates of access to the RAPIDGN and RADPIP benefit for the third and fourth quarters of 2022 and the first quarter of 2023.

Additionally, the certificates for the second, third and fourth quarters of 2023 were requested in a timely manner, and have not been granted as of the date of issuance of these Consolidated Financial Statements.

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, ENARSA and distributors.

2.2.4.1.3 Plan GasAr’s Round 5.2 – Aguaragüe Joint Operation

Pampa, jointly with all partners of the Aguaragüe Joint Operation, participated in Round 5.2 of Plan GasAr, called under SE Resolution No. 770/22, and was awarded this project. The companies making up the Joint Operation appended a single incremental activity plan with an expected natural gas production incremental volume for the Joint Operation exceeding 400,000 m3/d as from the last quarter of 2023. The Company holds a 15% stake in this Joint Operation.

On September 27, 2023, gas volumes under Plan GasAr - Round 5.2 were awarded pursuant to SE Resolution No. 799/23. The scheme provides for the sale of incremental volumes to ENARSA for the October 1, 2023-December 31, 2028 period. The agreed sales price amounts to US$ 9.8 /MMBTU between October 2023 and December 2026, and US$ 6 /MMBTU between January 2027 and December 2028.

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, 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 2023 and 2022, an average of 287 million m3/day and 451 million m3/day were awarded to GasAr Plan beneficiaries at US$ 3.4 MBTU and US$ 3.5 MBTU, respectively (185 million m3/day and 276 million m3/day, respectively, corresponding to the Neuquina Basin).

Additionally, in 2023, 25 million m3/day were awarded in complementary calls at US$2.6/MBTU (of which 15 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.

On April 19, 2023, the SE notified the Company of the extension of the Neuquina basin’s natural gas export quota for the next winter period, consisting of: (i) an extraordinary and priority quota of 2 million m3/d for the months of May and June 2023, assignable pro rata among the “July Flat Gas Commitment” awardees, and (ii) a firm winter export quota under Plan GasAr for a 3 million m3/d volume for the months of July, August and September 2023.

In this sense, the Company was assigned an additional volume of 872,727 m3/, totaling a 2,181,818 m3/d export quota for the months of May and June. The volume assigned for the months of July, August and September was 857,449 m3/d. Regarding the minimum price for export permits, it will remain at US$ 7.73/MMBTU.

Moreover, the following export quotas for the period between October 2023 and April 2024 were assigned: 9 million m3/d for the Neuquina Basin and 2 million m3/d for the Austral Basin. The minimum price will result from calculating the simple average Brent oil prices in the first fifteen days of the month prior to delivery, multiplied by 7%. The Company was assigned a 1,452,878 m3/d volume.

Besides, the SE set an export quota of a total of 5.9 million m3/d for the winter period (May-September 2024) and a total of 9 million m3/d for the summer period (October-December 2024). In line with its participation in Plan GasAr, the Company was assigned a volume of 610,989 m3/d for the winter period and 606,529 m3/d for the summer 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 ENARSA 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, (Tratayén - Salliqueló).

Later, PEN Executive Order No. 76/22, published on February 14, 2022, granted ENARSA 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. ENARSA 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 ENARSA. Moreover, ENARSA may fully or partially assign ownership of its concession to YPF.

Besides, the “Argentine Gas Development Fund” administrative and financial trust was created, with ENARSA 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.

In July 2023, cleaning and filling operations were conducted in the new Tratayén – Salliqueló tranche of President Néstor Kirchner gas pipeline, and transportation operations pursuant to regulatory requirements and standards started as from August 3, 2023.

President Néstor Kirchner Gas Pipeline’s Tratayén – Salliqueló tranche, crosses the provinces of Neuquén, Río Negro, La Pampa and Buenos Aires, with a 573 km extension and an initial transportation capacity of 11 million m3/day of gas produced at the Vaca Muerta field.

Furthermore, on August 25, 2023, a call for tenders was launched for the Northern gas pipeline reversion project, complementary works to President Néstor Kirchner gas pipeline consisting of the engineering and construction of the 122-km Tio Pujio – La Carlota gas pipeline, the 62-km expansion of the Northern gas pipeline and the reversion of four compression plants in the provinces of Córdoba, Santiago del Estero and Salta. As of the issuance of these consolidated condensed interim financial statements, ENARSA, after declaring the call for tenders for line 1 unawarded, granted the construction of lines 2 and 3 of the Northern gas pipeline reversion project to the Techint-SACDE Joint Venture and will call for a new abbreviated tender process for line 1 of the pipeline.

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, later extended by PEN Executive Order No. 815/22, launching the renegotiation of the RTI concluded in 2018 while suspending renegotiation agreements in force until December 16, 2023 and providing 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 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.

On March 16, 2023, TGS’s Board of Directors approved a proposed addendum to the renegotiation transitionary agreement (the “2023 RTT”) sent by ENARGAS. On April 27, 2023, ENARGAS issued Resolution No. 186/23 publishing the new effective tariff schemes. The 2023 RTT was later ratified by PEN Executive Order No. 250/23 dated April 29, 2023.

The 2023 RTT includes, effective from April 29, 2023, a 95% transitionary tariff increase on the natural gas transportation tariff and the access and use charge. While it is in force, TGS may not distribute dividends or directly or indirectly early cancel financial and commercial debts taken on with shareholders, acquire other companies or grant loans, except for loans benefiting users or granted to contractors not covered by the previously indicated cases. If TGS deems it appropriate to act otherwise, it should require the corresponding authorization.

On December 14, 2023, a public hearing was called for January 8, 2024 under ENARGAS Resolution No. 704/23. As of the date of issuance of these Consolidated Financial Statements, the applicable regulations authorizing a transitional tariff increase while the RTI process is underway have not been issued.

On December 16, 2023, PEN Executive Order No. 55/23 was issued, declaring the emergency in the national energy sector until December 31, 2024. Among other issues, this executive order: (i) extends the validity of PEN Executive Order No. 1020/20, (ii) establishes the launching of the RTI process, (iii) sets ENARGAS’ public audit as from January 1, 2024, and (iv) instructs the SE to issue the necessary rules and procedures for sanctioning market prices for the natural gas transmission utility.

2.3.2 License extension request

On September 8, 2023, TGS submitted a request to ENARGAS to initiate a license term extension proceeding, as contemplated in Act No. 24,076, and requested the adoption of the existing performance assessment and public hearing measures so that, once all established administrative formalities and proceedings are met, a 10-year extension may be granted as from the initial term, effective on December 28, 2027, for the provision of the gas transportation service contemplating all the scopes of the license approved by Executive Order No. 2,458/92.

As of the date of issuance of these Consolidated Condensed Interim Financial Statements, TGS has not received a formal response from ENARGAS regarding this request.

2.3.3 Regulatory framework of the segment of Production and Commercialization of Liquids

2.3.3.1 Domestic market

The production and commercialization of liquids segment is not subject to regulation by ENARGAS. However, over recent years, the Argentine Government enacted regulations which significantly impacted it.

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. Initially, a payment of compensation to the Household Plan participating producers was established, which was eliminated as from February 2019.

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, 2023, the Argentine Government owes TGS $ 4,676 million under these items.

2.3.3.2 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.

During 2023, TGS participated in the Export Increase Program (see Note 2.6.4).

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.

On April 20, 2023, under ENRE Resolution No. 364/23, the ENRE launched the comprehensive tariff review process (“RTI”) for electricity transmission companies pursuant to Act No. 24,065 and Act No. 27,541, setting a 30-day term to draw up the guidelines and schedule for its development.

On May 29, 2023, ENRE Resolution No. 421/23 approved the transmission tariff review program for the year 2023 and the first quarter of 2024, and provided for the ENRE´s notification of the schedule and information requirements during the months of September and October 2023. In this sense, under a note dated October 26, 2023, the ENRE filed a first request for information, mainly associated with a description of the facilities making up the transportation system, expansions under execution, investment plans and corridors’ saturation status. On October 27, 2023, Transener and Transba answered that they would comply with such request in due time and manner, but that it would be necessary for the ENRE to define: i) the complete RTI process schedule, ii) the economic, financial and regulatory criteria under which such process will be conducted; and iii) issues regarding the first management period.

On September 8, 2023, aiming to preserve the purchasing power of the revenues established in ENRE Resolutions No. 147/22 and 148/22, the ENRE issued Resolutions No. 660/23 and 661/23 setting the hourly remuneration values effective from August 1, 2023, which represent 20.9% and 20.84% increases over the January 2023 values for Transener and Transba, respectively. Likewise, pursuant to ENRE Resolutions No. 780/23 and 781/23, on November 1, 2023, hourly remuneration values effective from November 1, 2023 were established, which represented a 37.33% and 38.44% increase over the values effective from August 2023 for Transener and Transba, respectively.

Furthermore, PEN Executive Order No. 55/23, dated December 16, 2023, declared the emergency in the national energy sector until December 31, 2024. Among other issues, the mentioned executive order established the launching of the tariff review process in accordance Article 43 of Law No. 24,065 for public electricity distribution and transmission companies under federal jurisdiction and established that the entry into force of the resulting tariff schedules may not exceed December 31, 2024.

Consequently, on January 2, 2024, through ENRE Resolution No. 3/24, a Public Hearing was called, which was held on January 29, 2024, in order to 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.

Finally, through ENRE Resolutions No. 104/24 and 105/24, hourly remuneration values effective as from February 19, 2024 (date of publication in the BO) were established, which represented an increase of 179.7% and 191.1% compared to the values in force since November 2023 for Transener and Transba, respectively. Likewise, the tariff adjustment rate to be applied on monthly bases as from May 2024, was determined according to a formula based on wage index, wholesale prices index and consumer prices index.

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. Specifically, as from December 11, 2023, any demand for foreign currency at the MLC requires BCRA’s prior authorization.

The following are certain exceptions to the prior authorization requirement for access to the MLC:

Firstly, access to the MLC for outflows without BCRA’s prior authorization is allowed through the submission of an affidavit declaring that all foreign currency holdings in the country are deposited in accounts with local financial institutions and that no liquid foreign assets are held for an amount exceeding US$ 100,000. In case such liquid foreign assets exceed US$ 100,000, an additional affidavit may be filed stating that there is no such excess amount because payments were made for the MLC through swap and/or arbitrage transactions with deposited funds.

As from December 13, 2023, the MLC may be accessed, without BCRA’s prior authorization, for deferred payments of new imports of goods with customs entry registration, depending on the type of good and according to the schedules provided. Besides, regarding the payment of services rendered by non-residents, and depending on the type and term of payment, the MLC may be accessed once such services have accrued and/or been rendered.

Moreover, if access to the MLC has been requested, the entry and settlement in the MLC of the funds received abroad originating from the collection of loans granted to third parties, the collection of term deposits or the sale of any kind of asset is mandatory within 5 business days of their availability, when the asset has been acquired, the deposit has been created, or the loan has been granted after May 28, 2020.

Regarding the trading of stock market assets, it is established that access to the MLC may be granted without BCRA’s prior authorization by submitting an affidavit stating that, on the date of access to the MLC and in the previous 90 or 180 calendar days, in case securities issued under Argentine law or foreign law, respectively, are used, whether directly or indirectly or for the account and order of third parties, no sales of securities issued by residents to be settled in foreign currency, exchanges of securities issued by residents for foreign assets, transfers of securities to foreign depositories, acquisitions in the country of securities issued by non-residents to be settled in pesos, acquisitions of CEDEAR representing foreign shares, acquisitions of securities representing private debt issued in foreign jurisdictions, or deliveries of funds in local currency or other local assets (except funds in foreign currency deposited in local financial entities) have been made to any person (whether a person or legal entity, resident or non-resident, related or not), resident or non-resident, and whether or not affiliated), receiving as prior or subsequent consideration, directly or indirectly, on its own or through an affiliated, controlled or controlling entity, foreign assets, crypto-assets or securities deposited abroad; and finally, there must be a commitment not to enter into the detailed transactions during the 90/180 calendar days following the request for access to the MLC. Likewise, for access to the MLC by legal entities, an additional affidavit must be submitted stating: (a) details of the individuals or legal entities exercising a direct control relationship according to BCRA’s regulations; and (b) that on the day on which access to the MLC is requested and in the previous 180 days, no funds in local currency or other liquid local assets (except funds in foreign currency deposited in local financial entities) were delivered in Argentina to any individual or legal entity exercising direct control, or to other companies making up the same economic group, except those directly associated with regular transactions for the acquisition of goods and/or services. The requirement stated in item (b) is deemed met if an affidavit is filed regarding transactions with securities of each of these individuals or legal entities pursuant to the current exchange regulations. Finally, on September 28, 2023, the BCRA established that sales of securities to be settled in foreign currency in the country or abroad should not be taken into consideration when all the funds obtained from such settlements have been or are used within 10 calendar days following certain transactions listed in BCRA regulations.

On its part, the BCRA extended the obligation to submit a refinancing plan for certain debts and principal maturities scheduled up to December 31, 2023, based on the following criteria: (i) access to the MLC for up to 40% of the principal amount, in the original term; and (ii) the refinancing of the principal balance, with new foreign indebtedness with an average maturity 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. Likewise, the BCRA accepts access to the MLC for the cancellation of financial indebtedness abroad (provided they are not related parties) during the month of December 2023 as from the payable principal or interest’s maturity date. Access is also possible up to 3 business days before the maturity date if the payment is made by means of an exchange and/or arbitration against a local foreign-currency account held by the customer authorized to make such payment.

Additionally, in October 2022, the Integrated System for Monitoring Imports (“SIMI”) and the Integrated System for Monitoring Foreign Payments of Services (“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, the BCRA established that no more advance, sight or deferred payments, or payments of commercial debts with no customs registration may be made through these new mechanisms, except for certain cases contemplated in the regulation. Subsequently, on December 26, 2023, the SIRA and SIRASE system was abrogated and a new system, called Statistical System for Imports (“SEDI”), was created. This system provides that: (i) the affidavit has a term of validity of 360 days from the exit status; (ii) the analysis of the tax situation and the economic-financial capacity is performed prior to the affidavit’s formalization; (iii) the state agencies will have 30 days to render a decision and, in the absence of a decision upon the expiration of such term, the affidavit will automatically go to exit status; and (iv) no information or approval must be required regarding the date of access to the MLC. Additionally, the Record of Commercial Debts for Imports with Foreign Suppliers is created for the registration of subjects having commercial debts for goods and/or services imports with a formalization date prior to December 13, 2023. The corresponding Group’s companies have been registered in the mentioned record.

Finally, the BCRA introduced adjustments 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 must appoint a single domestic financial entity responsible for issuing such certifications and recording the amounts recognized by the SE and the applicable period.

It is worth highlighting that the detailed information does not list all possibly applicable exchange regulations; for more information on Argentina’s exchange rate policies, please visit the Central Bank’s website: www.bcra.gov.ar.

2.6 Tax regulations - 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 is 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 10.6).

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. The Company and its subsidiaries paid an income tax prepayment for $ 1,863 million for the year 2022.

On December 4, 2023, AFIP’s General Resolution No. 5,453/23 was published in the BO, establishing a new income tax prepayment by taxpayers and responsible persons listed in Section 73 of Law No. 20,628, as amended, meeting the following conditions: (i) main activity of crude oil and natural gas extraction, oil refining products manufacturing and conventional thermal energy generation; and (ii) taxable income, without deduction of prior years' losses, in an amount equal to or exceeding $ 600 million. The Company and its subsidiaries have not been affected by this resolution.

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.

Law No. 27,541 provided that, as regards the positive or negative fiscal inflation adjustment determined as a result of the application of the adjustment provided for by Title VI of the Income Tax Law corresponding to the first and second fiscal year starting as from January 1, 2019, one-sixth should be charged in that fiscal period and the remaining five sixths, in equal parts, in the five immediately following fiscal periods.

On December 1, 2022, Law No. 27,701 was published in the BO, which established that taxpayers determining a positive inflation adjustment in the first and second fiscal year starting from January 1, 2022 (inclusive) may allocate one-third in that fiscal period and the remaining two-thirds, in equal parts, in the two immediately following fiscal periods. This computation only applies to subjects making investments in the purchase, construction, manufacture, production or final import of property, plant and equipment, except automobiles, during each of the two fiscal periods immediately following that in which the computation of the first third of the period in question exceeds or equals $ 30,000 million.

As of issuance of these Consolidated Financial Statements, this provision has not yet been regulated.

The Company and its subsidiaries determine and disclose the impact of the tax inflation adjustment for each of the fiscal periods in which it is applicable.

2.6.2 Value-added tax

A procedure is established for the reimbursement of tax credits originated in investments in property, plant and equipment which, after 6 months as from their assessment, have not been absorbed by tax debits generated by the activity.

2.6.3 Tax for an Inclusive and Caring Argentina (Impuesto Para una Argentina Inclusiva y Solidaria, “PAIS”) for import and foreign service procurement transactions

Executive Order No. 377/23, dated July 24, 2023, extends the application of the PAIS tax to the acquisition of services abroad and import transactions for certain goods, exempting goods associated with the energy sector pursuant to SE regulations. Moreover, its regulation under AFIP Resolution No. 5,393/23, dated July 25, 2023, provided for an advance payment offsettable against the PAIS tax equivalent to 95% of the total final tax payable for certain goods and merchandise. This advance payment should be paid by the importer when declaring the import’s intended use. The PAIS tax’s remaining 5% balance should be paid when accessing the MLC to make the payment abroad, where the intervening bank will act as collection and settlement agent.

PAIS tax exemption for import transactions

SE Resolutions No. 671/23, 714/23, 824/23 and 955/23 regulated the PAIS tax exemption for import transactions of goods associated with the energy sector.

Thus, the following import transactions are exempted from this tax:

liquid fuels, natural gas and electricity;

ii)

goods destined for the construction and start-up of President Néstor Kirchner Gas Pipeline, the reversion of the Northern Gas Pipeline and related works, and the works making up the Gas Pipeline Network Program;

iii)

goods destined for power generation works with or without foreign financing for the payment of imports;

iv)

goods for works and maintenance of renewable energy generation projects comprised in exhibits to the regulatory resolutions, including PEPE II through IV, PE Arauco and PEPE VI wind farms;

goods for works and maintenance of thermal and hydropower plants included in the lists attached to the regulatory resolutions, including the Company assets.

2.6.4 Export Increase Program

On October 3, 2023, SE Resolution No. 808/23 temporarily included the products sold by the Company, among other exports, under the Export Increase Program created by PEN Executive Order No. 576/22.

Under this program, at least 75% of the export values had to be entered into the country in foreign currency, and the remaining 25% could be settled in pesos through the purchase of marketable securities for exports settled October 2 through 20, 2023, with an effective export date up to November 30, 2023. The Company opted into this program.

Subsequently, PEN Executive Orders No. 549/23 and No. 597/23 reduced to 70% and 50%, respectively, the minimum foreign currency settlement percentage for exports settled in the October 23-November 17, 2023 and November 20-December 10, 2023 periods, respectively.

Finally, PEN Executive Order No. 28/23 established a minimum income equivalent to 80% of the value of exports in foreign currency, and the remaining 20% would be settled in pesos through the purchase of marketable securities as from December 13, 2023.