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REGULATORY FRAMEWORK

12 Months Ended

Dec. 31, 2021

NOTE 2: REGULATORY FRAMEWORK

2.1

Generation

2.1.1 Generation units

The Company’s revenues related to this segment come from: i) sales contracts with large users within the MAT (Resolutions No. 1,281/06 and No. 281/17); ii) supply agreements with CAMMESA (Resolutions No. 220/07, No. 21/16, No. 287/17 and Renovar Programs) and iii) sales to the Spot market pursuant to the provisions applicable within the WEM administered by CAMMESA (SRRYME Resolution No. 1/19 as from March 2019, SE Resolution No. 31/20 as from February 2020 and SE Resolution No. 441/21 as from February 2021). The Company’s generating units, held directly and through its subsidiaries and joint ventures, are detailed below:

In operation:

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. 440/21
CTG	GUEMTV12	TV	≤100 MW	Resolution No. 440/21
CTG	GUEMTV13	TV	>100 MW	Resolution No. 440/21
Piquirenda	PIQIDI 01-10	DI	≤42 MW	Resolution No. 440/21 ⁽²⁾
CPB	BBLATV29	TV	>100 MW	Resolution No. 440/21
CPB	BBLATV30	TV	>100 MW	Resolution No. 440/21
CT Ing. White	BBLMD01-06	MCI	100 MW	Resolution No. 21/16
CTLL	LDLATG01/TG02/TG03/TV01	CC	>150 MW	Resolution No. 440/21 ⁽²⁾
CTLL	LDLATG04	TG	105 MW	Res. No 220/07 (75%)
CTLL	LDLATG05	TG	105 MW	Resolution No. 21/16
CTLL	LDLMDI01	DI	≤42 MW	Resolution No. 440/21
CTGEBA	GEBATG01/TG02/TV01	CC	>150 MW	Resolution No. 440/21
CTGEBA	GEBATG03	TG	169 MW	Energy Plus Res. No. 1,281/06
CTGEBA	GEBATG03/TG04/TV02	CC	400 MW	Resolution No. 287/17
Ecoenergía	CERITV01	TV	14 MW	Energy Plus Res. No. 1,281/06
CT Parque Pilar	PILBD01-06	MCI	100 MW	Resolution No. 21/16
CTB	EBARTG01 - TG02	TG	567 MW	Resolution No. 220/07
HIDISA	AGUA DEL TORO	HI	HI – Media 120<P≤300	Resolution No. 440/21
HIDISA	EL TIGRE	HI	Renewable ≤ 50	Resolution No. 440/21
HIDISA	LOS REYUNOS	HB	HB – Media 120<P≤300	Resolution No. 440/21
HINISA	NIHUIL I - II - III	HI	HI – Small 50<P≤120	Resolution No. 440/21
HPPL	PPLEHI	HI	HI – Media 120<P≤300	Resolution No. 440/21
P.E. M. Cebreiro	CORTEO	Wind	100 MW	Renovar
PEPE II	PAMEEO	Wind	53 MW	MAT Resolution No. 287/17
PEPE III	BAHIEO	Wind	53 MW	MAT Resolution No. 287/17

⁽¹⁾	Subsequent power and energy is remunerated in the spot market according to Resolution No. 440/21.
⁽²⁾	During the months of July and October, the contracts under Resolution No. 220/07 of CTP and TV01 of CTLL, respectively, have ended. Power and energy will be remunerated in the spot market according to Resolution No. 440/21.

In construction:

Generator	Tecnology	Capacity	Applicable regime
Generator	Tecnology	Capacity	Applicable regime
CTB	CC	280 MW	Resolution No. 220/07
PEPE III	Wind	81 MW	MAT Resolution No. 287/17

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 would remunerate newly installed generation sold to a certain category of Large Users at higher prices.

The Energy Plus service consists of the offer of additional generation availability by generators, co-generators and self-generators which, as of the date of publication of SE Resolution No. 1,281/06, were not WEM agents or did not have facilities or an interconnection with the WEM. Considering that:

These plants should have fuel supply and transportation facilities;

The energy used by GU300 in excess of the base demand (energy consumption for 2005 year) qualifies for Energy Plus agreements within the MAT at a price negotiated between the parties; and

For new GU300 entering the system, their base demand will equal zero.

If a generator cannot meet the power demand by an Energy Plus customer, it should purchase that power in the market at the operated marginal cost, or, alternatively, support the committed demand in case of unavailability through agreements with other Energía Plus generators.

Currently, the Company has Power Availability agreements in force with other generators whereby, in case of unavailability, it may purchase or sell power to support the contracts mutually.

Furthermore, the SE, through Note No. 567/07, as amended, established that GU300 not purchasing their surplus demand in the MAT should pay the Average Incremental Charge of Surplus Demand. As from the month of June 2018, pursuant to SE Note No. 28663845/18, the CMIDE became the greater of $1,200/MWh or the temporary dispatch surcharge.

Under this regime, the Company —through its power plants Güemes, EcoEnergía and Genelba— sells its energy and power capacity for a maximum amount of 283 MW. The values of Energy Plus contracts are mostly denominated in U.S. dollars.

2.1.2.2 Renewable Energy Term Market (“MATER” Regime)

Pursuant to Resolution No. 281/17, the MEyM regulated the MATER Regime with the purpose of setting the conditions for large users within the WEM and WEM distributing agents’ large users covered by Section 9 of Law No. 27,191 to meet their demand supply obligation from renewable sources through the individual purchase within the MATER from renewable sources or self-generation from renewable sources.

Projects destined to the supply of electric power from renewable sources under the MATER Regime may not be covered by other remuneration mechanisms, such as the agreements under the Renovar rounds. Surplus energy is sold in the spot market.

Finally, contracts executed under the MATER Regime are administered and managed in accordance with the WEM procedures. The contractual terms —life, allocation priorities, prices and other conditions, notwithstanding the maximum price set forth in Section 9 of Law No. 27,191— are freely agreed between the parties, although the committed electricity volumes are limited by the electric power from renewable sources produced by the generator or supplied by other generators or suppliers with which it has purchase agreements in place.

Within the framework of this regime, the Company, through its PEPE II and III wind farms, sells energy for a maximum amount of 106 MW and, additionally, has started selling third-party generators’ renewable energy for an approximate volume of 2 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 between 500 and 1,500 US$/MW/month.

Additionally, it allows projects with an assigned dispatch priority but not yet commissioned to continue their execution keeping the dispatch priority, or to waive such priority, thus releasing the transmission capacity.

The Company, as owner of the PEPE IV Wind Farm project, located in Las Armas, Province of Buenos Aires, notified its decision to waive the timely granted dispatch priority, and recovered the security it had provided. As a result, CAMMESA notified that the already initiated execution of the security was determined to be moot as it had no further claim against the Company; therefore, as of September 30, 2021, the amount of US$ 12.5 million recorded for to such effect was recovered and disclosed under the item “Other operating income” of the Consolidated Statement of Comprehensive Income.

Under MEyM Resolution No. 281/17, the term for submitting MATER dispatch priority requests for the third quarter of 2021 expired on September 30, 2021. Given the large number of projects submitted, a tie-breaking mechanism was implemented on October 29, 2021 to define priority allocation based on the available transmission capacity. The Company presented a 50 MW extension project for the de la Bahía wind farm (PEPE III) and was awarded a 36 MW dispatch priority. The Company estimates it may obtain the dispatch priority for the remaining power capacity in future rounds.

For further information on the extension project, see Note 17.1.

2.1.3 Supply Agreements with CAMMESA

2.1.3.1 SE Resolution No. 220/07

Aiming to encourage new investments to increase the generation offer, the SE passed Resolution No. 220/07, which empowers CAMMESA to enter into Agreement with WEM Generating Agents for the energy produced with new equipment. These will be long-term agreements and the price payable by CAMMESA should compensate for the investments made by the agent at a rate of return to be accepted by the SE.

Under this regulation, the Company, through Loma la Lata and Ensenada de Barragán thermal power plants, has contracts with CAMMESA to sell energy and power capacity for a total amount of 646 MW. In turn, the Ensenada de Barragán thermal power plant has an expansion project underway to add 280 MW under this scheme, which commissioning is estimated for the third quarter of 2022. For further information on the project to the CC at CTB, see Note 5.2.3.

It is worth highlighting that some contracts for the Piquirenda and Loma de la Lata power plants, for a total of 210 MW, expired in July and October 2021, respectively.

2.1.3.2 SE Resolution No. 21/16

As a result of the state of emergency in the national electricity sector, 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 offered), less penalties and fuel surpluses. Surplus power capacity is sold in the spot market.

Pursuant to this resolution, the Company, through its Loma de la Lata, Ingeniero White and Pilar thermal power plants, has effective agreements with CAMMESA for the sale of energy and power capacity for a total 305 MW.

2.1.3.3 SE Resolution No. 287/17

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

For the awarded projects, wholesale power purchase agreements were entered into for a term of 15 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 offered), less penalties and fuel surpluses. Surplus power capacity is sold in the spot market.

Pursuant to this regulation, the Company, through its Genelba thermal power plant, has entered into an agreement with CAMMESA for the sale of energy and power capacity for a total 400 MW.

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, accelerated depreciation of the income tax, import duty exemptions, etc.) and the creation of a fund for the development of renewable energies destined, among other objectives, to the granting of loans and capital contributions for the financing of such projects.

Recently, the SE passed Resolution No. 1,260/21 to address issues regarding the projects under the different Renovar rounds that did not meet committed commissioning terms. Upon satisfaction of certain conditions, the resolution gives project awardees the option to: i) terminate the current contract with CAMMESA against the payment of a sum of money; ii) amend the contract and extend the term for commissioning against a reduction in the contract price and term; iii) commission the project for a power capacity lower than that committed initially.

Under the Renovar programs, the Company, through Greenwind, has a supply agreement in place with CAMMESA for a total of 100 MW for the PE Mario Cebreiro project, which was commissioned in 2018, within the timely committed term.

2.1.4 Remuneration at the Spot market

Resolution SRRYME No. 1/19 applicable as from March 2019, established remunerative items based on technology and scale with US$-denominated prices payable in $ by applying BCRA’s exchange rate.

On February 27, 2020, SE Resolution No. 31/20 was published in the BO, which superseded the remuneration scheme established by SRRYME Resolution No. 1/19, and provided as follows: i) reduced U.S.-denominated values for available power capacity, maintaining the values of the remuneration for generated and operated energy; ii) translated remuneration values to Argentine pesos at a 60 $/US$ exchange rate; and iii) set an additional remuneration, in pesos, for the power capacity generated during the hours of maximum thermal demand of the month, taking into consideration the average power capacity generated by thermal generators and the average power capacity operated by hydroelectric generators.

Besides, SE Resolution No. 31/20 set a monthly remuneration update scheme with a factor contemplating a 60% CPI and 40% IPIM adjustment. However, on April 8, 2020, through Note No. 2020-24910606-APN-SE#MDP, the SE instructed CAMMESA to postpone the application of this automatic adjustment mechanism.

On May 19, 2021, SE Resolution No. 440/21 provided for a 29% increase in spot generation remuneration values, and repealed the automatic adjustment mechanism established by SE Resolution No. 31/20. This increase to be applied as from the economic transaction for February 2021, provided the generator waives/dismisses all administrative/judicial claims filed on account of the failure to apply the automatic adjustment formula provided for by SE Resolution No. 31/20 within 30 days as from SE Resolution No. 440/21publication, or as from the month in which the generator submits its waiver/dismissal, if later. The waiver includes the obligation to withdraw any claim brought by the generating agent’s shareholders on account of the failure to apply the automatic adjustment mechanism provided for by SE Resolution No. 31/20, whether in Argentina or abroad.

The Company and its subsidiaries filed the waiver/dismissal within the previously indicated 30-day period.

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	SRRYME No. 1/19 (US$ / MW-month)	SE No. 31/20 ($ / MW-month)	SE No. 440/21 ($ / MW-month)
Large CC Capacity > 150 MW	3,050	100,650	129,839
Large ST Capacity > 100 MW	4,350	143,550	185,180
Small ST Capacity ≤100 MW	5,200	171,600	221,364
Large GT Capacity > 50 MW	3,550	117,150	151,124

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

Period

SRRYME No. 1/19

(US$ / MW-month)

SE No. 31/20

($ / MW-month)

SE No. 440/21

($ / MW-month)

Summer - Winter

7,000

360,000

464,400

Fall - Spring

5,500

270,000

348,300

In the case of thermal power plants with a power capacity equal to or lower than 42 MW in total, the current resolution applies a minimum remuneration of 402,480 $/MW-month, and a remuneration of 541,800 $/MW-month and 425,700 $/MW-month for the guaranteed power capacity in the summer-winter and fall-spring periods, respectively.

Likewise, a coefficient derived from the average utilization factor over the unit’s last twelve months is applied to the power capacity remuneration: with a minimum 70% of the utilization factor, 100% of the power capacity payment is collected; if the utilization is between 30% and 70%, the power capacity payment ranges from 70% to 100%; and if the utilization factor is lower than 30%, 70% of the power capacity payment was collected until January 2020 and 60% of the power capacity payment is collected as from February 2020 (see transitional measure in Note 2.1.4.3).

Since February 2020 an additional remuneration for the hours of maximum thermal requirement of the month (hmrt) was established, which corresponds to the 50 hours with the largest dispatch of thermal generation of each month divided into two blocks of 25 hours each, applying the following prices to the average generated power:

Period	SE No. 31/20		SE No. 440/21
Period	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)
Summer – Winter	45,000	22,500	58,050	29,025
Fall - Spring	7,500	-	9,675	-

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 at all hours within the period is considered to calculate availability.

The base remunerations includes the following scales and prices:

Technology / Scale	SRRYME No. 1/19 (US$ / MW-month)	SE No. 31/20 ($ / MW-month)	SE No. 440/21 ($ / MW-month)
Medium HI Capacity > 120 ≤ 300 MW	3,000	132,000	170,280
Small HI Capacity > 50 ≤ 120 MW	4,500	181,500	234,135
Medium Pumped HI Capacity > 120 ≤ 300 MW	2,000	132,000	170,280
Renewable HI Capacity ≤ 50 MW	8,000	297,000	383,130

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.

Lastly, an additional remuneration was established amounting 500 US$/MW-month for pumping power plants and 1,000 US$/MW-month for conventional plants, effective until January 2020. The allocation and collection of 50% of the additional remuneration were conditional upon the generator taking out insurance, to CAMMESA’s satisfaction, to cover for major incidents on critical equipment, and upon the progressive updating of the plant’s control systems under an investment plan to be submitted based on criteria defined by the SEE. Later, an additional remuneration was set for the hours of maximum thermal demand (hmrt), corresponding to the 50 hours with the largest dispatch of thermal generation in each month, divided into two blocks of 25 hours each:

Period	SE No. 31/20		SE No. 440/21
Period	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)	First 25 hours ($ / MW-hmrt)	Second 25 hours ($ / MW-hmrt)
Summer - Winter	39,000	19,500	50,310	25,155
Fall - Spring	6,500	-	8,385	-

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

SRRYME No. 1/19

(US$ / MWh)

SE No. 31/20

($ / MWh)

SE No. 440/21

($ / MWh)

Generated energy

Between 4 and 7

Between 240 and 420

Between 310 and 542

Operated energy

1.4

108

It is worth highlighting that if the thermal generation unit operates outside its optimal dispatch, the remuneration for generated energy will be recognized 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

SRRYME No. 1/19

(US$ / MWh)

SE No. 31/20

($ / MWh)

SE No. 440/21

($ / MWh)

Generated energy

3.5

210

271

Operated energy

1.4

108

The remuneration for operated energy should correspond with the grid’s optimal dispatch; however, the current resolution does not indicate which would be the consequence otherwise.

In the case of pumping hydroelectric power plants, both the generated energy and that used for pumping are considered. Besides, if it works as a synchronous condenser, 60 $/MVAr and 77 $/MVAr are recognized under SE Resolution No. 31/20 and No. 440/21, respectively, for the megavolt-amperes exchanged with the grid when required, in addition to the prices for operated energy.

Unconventional sources remuneration

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

Remuneration

SRRYME No. 1/19

(US$ / MWh)

SE No. 31/20

($ / MWh)

SE No. 440/21

($ / MWh)

Generated energy

1,680

2,167

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 Transitory additional remuneration

On November 2, 2021, SE Resolution No. 1,037/21 provided as follows: (i) the creation of an exports account in the WEM’s stabilization fund for the accumulation of income from electricity export transactions conducted by CAMMESA, as from the economic transactions for the month of September 2021, for the financing of energy infrastructure works; and (ii) the transitory recognition of an additional remuneration to the one established by SE Resolution No. 440/21 for the economic transactions comprised between September 1, 2021 and February 28, 2022. On November 9, 2021, the SE, through Note NO-2021-108163338-APN-SE#ME, instructed CAMMESA to assume that covered generators have a 70% utilization factor, therefore, 100% of the power capacity remuneration would be paid, and added an amount of $ 1,000/MWh for exported energy, which will be distributed proportionately to the energy generated monthly by each generator.

2.1.4.4 Suspension of contracts within the MAT

The suspension of contracts within the MAT (excluding those derived from a differential remuneration scheme) provided for by SE Resolution No. 95/13 remains in effect.

2.1.5 Fuel supply for thermal power plants

On November 6, 2018, SE Resolution No. 70/18 was published in the BO, which empowered generating, co-generating and self-generating agents within the WEM to acquire the fuels required for own generation; this resolution superseded SE Resolution No. 95/13, which provided that fuel supply for electric power generation would be centralized in CAMMESA (with the exception of generation under the Energy Plus regime). Under the scheme set forth by SE Resolution No. 70/18, the cost of generation with own fuels was valued according to the mechanism for the recognition of the Variable Production Costs recognized by CAMMESA. During its term of validity, CAMMESA remained in charge of the commercial management and the dispatch of fuels for generators that did not or could not make use of this option.

In the seasonal programming conducted on November 12, 2018, the Company opted to make use of the self-supply option, and allocated a significant part of its natural gas production as an input for the dispatch of its thermal units.

On December 27, 2019, the Ministry of Productive Development passed Resolution No. 12/19, abrogating, effective as from December 30, 2019, SE Resolution No. 70/18, and re-establishing the validity of section 8 and section 4 of SE Resolutions No. 95/13 and 529/14, respectively, thus restoring 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 2.2.2.1.2), SE Resolution No. 354/20 was passed, which established a new dispatch order for generation units based on the fuel supplied for their operation under a centralized dispatch scheme.

SE Resolution No. 354/20 established the gas volumes CAMMESA should prioritize in the electricity dispatch. In this sense, firm volumes to be used by CAMMESA were defined, including: i) volumes corresponding to contracts entered into by CAMMESA with producers acceding to the GasAr Plan; ii) volumes corresponding to contracts executed by adherent producers with generators acceding to the centralized dispatch (these volumes will be discounted by the adherent producers from the applicable quota for which they should enter into contracts with CAMMESA under the GasAr Plan) and; iii) volumes to meet the Take or Pay (“TOP”) obligations under the supply agreement entered into between IEASA and Yacimientos Petrolíferos Fiscales Bolivianos (“YPFB”).

Besides, an electricity dispatch priority scheme was set based on the allocation of the natural gas quota taking into consideration the TOP obligations. To this effect, the following priorities were set (within each priority level, the order of agents is set based on the generator’s production cost):

(i)

Dispatch Priority 1: Generators, Self-generators and/or Co-generators supplied with a natural gas quota under a TOP Bolivia condition assigned by IEASA. If a generator with a fuel stocking obligation optionally acquires from IEASA natural gas from Bolivia, this volume will be included in this quota.

(ii)

Dispatch Priority 2: Generators, Self-generators and/or Co-generators supplied by CAMMESA with a natural gas quota from the centralized list of volumes up to the TOP of each contract.

(iii)

Dispatch Priority 3: Generators, Self-generators and/or Co-generators supplied by CAMMESA with a natural gas quota from the centralized list of volumes for the Daily Maximum Amount (DMA) less those corresponding to the TOP of each contract.

(iv)

Dispatch Priority 4: Generators, Self-generators and/or Co-generators supplied by CAMMESA with natural gas or LNG coming from other firm commitments undertaken by CAMMESA.

(v)

Dispatch Priority 5: Generators, Self-generators and/or Co-generators supplied with a gas quota from the unassigned, spot natural gas contracts from any source, acquired by CAMMESA and/or the Generator, according to the supply source. In the case of a generator with its own fuel, the maximum amount to be acknowledged will be the corresponding reference prices.

As regards the costs associated with the supply of these fuels, it was established that the electricity demand will bear, among others, the regulated transportation costs, the cost of natural gas and the applicable TOP obligations.

Generating agents that kept the possibility to purchase their fuel supply (agents under the Energy Plus regime or with Wholesale Purchase Agreements under Resolution SE No. 287/17) could opt in or out of CAMMESA’s unified dispatch, through the operating assignment of the contracted firm transportation and gas volumes, which impact the assigned priority order. Under such assignment, agents should waive all claims regarding the application of SE Resolution No. 354/20.

In the specific case of generators with Wholesale Power Purchase Agreements under SE Resolution No. 287/17, it was provided that they would have the option of canceling the self-supply obligation and the resulting recognition of its associated costs, having to maintain the respective transportation capacity for its management in the centralized dispatch.

The Company assigned the firm transportation and gas volumes committed to supplying Genelba Plus’ CC and Energy Plus contracts, setting certain guidelines for calculating fuel costs to support its Energy Plus contracts.

In the case of the supply to Genelba Plus’ CC, the assignment will remain effective during the life of the GasAr Plan, and it may be revoked by the generator with a minimum advance notice of 30 business days. Within this framework, the parties agreed to enter into an addendum to the Wholesale Power Purchase Agreement to establish the modifications regarding this new supply scheme, which execution is pending as of the issuance of these Consolidated Financial Statements.

2.1.6

Seasonal Programming

SE Resolution No. 24/21, published in the BO on January 15, 2021, approved the seasonal programming for the November 2020-April 2021 period. Seasonal prices remained unchanged until the month of April 2021, with reference prices being those in effect since 2019. In turn, the stabilized price set by SSEE Provision No. 75/18 for transmission in the extra high voltage system and the distributor-based main distribution price have remained unchanged.

As from April 2021, pursuant to SE Resolution No. 131/21 (amended by SE Resolutions No. 154/21 and 204/21), the reference price for power for the Distributor’s Large Users peak demand increases by 89% (except for public health and education organizations and agencies), reducing the gap with the actual cost and, consequently, subsidies. The remaining prices for electricity applicable to the end demand have not been modified.

On May 11, 2021 and November 1, 2021, SE Resolutions No. 408/21 and No. 1,029/21 were published, which approved the final seasonals reprogramming for winter (May 2021 – November 2021) and summer (November 2021 – April 2022), respectively, keeping unchanged the reference prices current as of April 30, 2021, and the stabilized price for the high-voltage and main distribution electricity transmission service established by SSEE Provision No. 75/18.

Later, SE Resolution No. 40/22, was published in February 2022, issued new reference prices for Distributor’s Large Users with increasing ranging between 13% and 24% according to the time of the day, and approved unsubsidized prices. It also maintained the values of the stabilized price for the high-voltage and main distribution electricity transmission service set by SSEE Provision No. 75/18.

SE Resolution No. 105/22, effective from March 1, 2022, increased energy reference prices for customer categories not subject to increases under SE Resolution No. 40/22, that is, public health and education entities, general and residential demand. Increases ranged between 34 and 50% for the WEM and between 10% and 20% for the Wholesale Electricity Market of Tierra del Fuego System. Additionally, new values were set for the stabilized price for the high-voltage and main distribution electricity transmission service, abrogating prices established in SSEE Provision No. 75/18.

2.1.7 Restructuring of Federal Government’s assets in the energy sector

The Federal Government has modified the policy adopted by the previous administration regarding the restructuring of assets in the energy sector, and has abrogated DNU No. 882/17, which provided for the sale of CTEB, CT Brigadier López, CT Manuel Belgrano II, IEASA’s stake in CITELEC, the Federal Government’s stake in Central Dique; CTG, Central Puerto, CT Patagónicas, TRANSPA, Dioxitek, and the Federal Government’s rights in TMB, TSM, Termoeléctrica Vuelta de Obligado and Termoeléctrica Guillermo Brown. In the opinion of the Company’s Management, this abrogation would not affect the rights acquired by the Company under CTEB’s goodwill transfer process.

Additionally, it provided for the transfer to IEASA of TMB and TSM’s shares held by the Federal Government. Earnings received by IEASA must be invested in energy infrastructure projects.

Finally, it granted to IEASA the exploratory permits for the MLO_115 and MLO_116 offshore areas and provided for the issuance of National Treasury guarantees as collateral for the contract for the acquisition of natural gas entered into with Bolivia.

2.2

Oil and gas

2.2.1 Argentine Hydrocarbons Law

On October 29, 2014, the National Congress enacted Law No. 27,007 amending Hydrocarbons Law No. 17,319 (enacted in 1967), which empowers the Government to grant exploration permits and concessions to the private sector. Additionally:

(i)

Sets the terms for exploration permits:

Conventional exploration: the basic term is divided into two periods of up to three years each, plus an optional extension of up to five years;

Unconventional exploration: the basic term is divided into two periods of four years each, plus an optional extension of up to five years; and

Continental shelf and off-shore exploitation: the basic term is divided into two periods of three years each, plus an optional extension of one year each.

(ii)

Sets the terms for exploitation concessions, extensible for 10-year terms:

Conventional exploitation concession: 25 years;

Unconventional exploitation concession: 35 years; and

Continental shelf and off-shore exploitation concession: 30 years.

(iii)

Sets transportation concessions will be granted for the same term than that granted for the originating exploitation concession.

(iv)

Sets prices for payments of exploration and exploitation levy and empowers the enforcement authority to establish the payment of extension and exploitation bonds.

(v)

Establishes a 12% royalty payable by the exploitation concessionaire to the grantor on the proceeds derived from liquid hydrocarbons extracted at wellhead and the production of natural gas. In the case of extension, additional royalties for up to 3% over the applicable royalties at the time of the first extension, up to a total of 18%, will be paid for the following extensions.

(vi)

Provides for two types of non-binding commitments between the National Government and the Provinces aiming to establish a uniform environmental legislation and to adopt a uniform tax treatment to encourage hydrocarbon activities.

(vii)

Restricts the National Government and the Provinces from reserving new areas in the future in favor of public or mixed companies or entities, irrespective of their legal form.

On its part, the Ministry of Energy and Natural Resources of the Province of Neuquén established certain parameters for the granting of Hydrocarbons Unconventional Exploitations Concessions (“CENCH”) in this province, instrumented through Resolution No. 53/20 dated July 1, 2020 and Resolution No. 142/21 dated November 24, 2021, and later ratified by Provincial Executive Order No. 2,183/21 in December 2021. Companies may request a CENCH based on a development project that will include a pilot plan for a term of up to five years to demonstrate its technical and economic feasibility. Furthermore, if companies request the inclusion in the CENCH of a surface larger than that assigned to the approved pilot plan, the payment of a block extension bond should be included, which value will be associated with the resources expected to be recovered in the extended block, considering the basin’s average price over the last two years. Besides, while the CENCH is in effect, companies should submit continuous development plans and investment commitments, updated annually.

2.2.2 Gas Market

2.2.2.1 Natural Gas Production Promotion Programs

2.2.2.1.1 Gas Plan II

In November 2013, pursuant to Resolution No. 60/13, the Committee created the Gas Plan II covering companies with no previous production or with a 3.5 MMm3/day production cap, establishing price incentives for production increases and penalties for the importation of LNG in case of breach of the committed volumes. Resolution No. 60/13, as amended (Resolutions No. 22/14 and No. 139/14), established a price ranging from US$ 4/MBTU to US$ 7.5/MBTU, based on the highest production curve attained.

In view of the receivables recorded by the Company in 2017 under the above-mentioned plan were not timely collected, on April 3, 2018, MINEM Resolution No. 97/18 established a procedure for the cancellation of compensations pending settlement and/or the payment of year 2017, payable in thirty monthly consecutive installments as from January 1, 2019. Beneficiary companies opting for the application of the procedure should state their decision to accede, waiving all present or future administrative and/or judicial actions, remedies, rights or claims regarding the payment of such obligations.

On May 2, 2018, the Company filed with the Ministry of Energy the application form to adhere to the payment procedure set forth by MINEM Resolution No. 97/18, expressing its consent to and acceptance of its terms and scope.

On February 21, 2019, SE Resolution No. 54/19 instrumented the cancellations by delivering public debt bonds accruing no interest and repayable in 29 monthly and consecutive installments. For this reason, on April 17, 2019 and July 16, 2019, bonds were credited in favor of the Company for a face value of US$ 89 million and US$ 54 million, respectively. As of December 31, 2021, the Company has collected all the installments contemplated as amortizations.

2.2.2.1.2 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. The most relevant aspects of this executive order include as follows:

(i) During its term of validity, as from May 2021, each signatory producer commits to supply an injection equal to or higher than the average injection for the May-July 2020 quarter per basin.

(ii) For off shore production, an additional term of 4 years is established (8 years in total), and the differential between the base production and the actual production will be offset with imported gas or injections exceeding those committed during the months of June, July and August of the first 4 years of the GasAr Plan.

(iii) Beneficiaries of other plans wishing to take part in the bid should file the waiver provided for in the regulation to be timely approved by the enforcement authority.

(iv) The SE will determine, with the assistance of ENARGAS and through a process including actual civic participation, the price for which the natural gas service providers may request the implementation of a tariff update on account of variations in the price of the natural gas purchased, which may be equal to or lower than the market price. The differential between the price determined by the enforcement authority and that offered will be borne by the Federal Government in the form of a compensation.

(v) The Federal Government undertakes to create a guarantee fund.

(vi) The recognition of tax credits subject to regulation.

(vii) The BCRA will establish appropriate mechanisms to facilitate access to the MLC, provided: funds have been entered through the MLC; and they are “genuine transactions” conducted after the entry into effect of the executive order and destined to the financing of projects under the GasAr Plan.

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 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. 125/2021 and AFIP General Resolution No. 4,939/2021.

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 I. 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 II 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 III 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 I. 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.

The awards granted to the Company represent a commitment of 11 million m3/day for the 2022-2024 winter periods and 9 million m3/day for the 2022-2024 summer periods; compared to 2020, it represents a 56% increase in winter production, the periods with the largest gas supply needs in the country. Based on the gas demand curve projected by the SE, the Company has entered into contracts with CAMMESA, IEASA, and the distributors, which are in effect from January 2021.

It is worth highlighting that this positioning minimizes contractual demand risks and makes it feasible for the Company to make a strong investment commitment, which will amount to approximately US$ 250 million over the four years of validity of GasAr Plan.

2.2.2.2 Natural gas for the residential segment and CNG

2.2.2.2.1 Natural gas price within the Transportation System Entry Point (“PIST”)

In mid-February 2019, a call for tenders was launched to supply natural gas to distribution companies on a firm TOP and DOP basis for up to 70% of the maximum daily volume, effective for 12 months as from April 2019. For the Noroeste Basin, 9.4 and 3.8 million m3 per day were assigned for the winter (April 2019– September 2019) and summer (October 2019 – April 2020), respectively, at an average price of US$ 4.35/MBTU. For the other basins, 36.1 and 14.4 million m3/day were assigned for the winter and summer, respectively, at an average price of US$ 4.62/MBTU.

Under ENARGAS Resolution No. 72/19, producers’ billing to distribution companies considered BNA’s average foreign exchange rate for the first 15 days of the month immediately preceding the beginning of each seasonal period (or, if lower, the exchange rate stipulated in the agreements). However, the exchange rate update applicable to the summer seasonal period (October 2019 - April 2020) was deferred several times. From April 2020, given the devaluation of the peso, added to the tariff freeze established by the Solidarity Law, pricing agreements were based on the range recognized in ENARGAS’ tariff schemes.

In December 2020, the call for tenders under GasAr Plan was conducted, agreeing on supply to gas distributors and power plants for the 2021 – 2024 period for a total of 67.4 million m3/day, 35% of which will be destined for distributors. The average tendered annual base price was US$ 3.5/MBTU, and an additional winter volume of 3.6 million m3/day was awarded at a yearly average base price of US$ 4.7/MBTU, exclusively destined to the priority demand. Pampa tendered and was awarded under this call.

2.2.2.3 Acquisition of Natural Gas for Generation

Since November 2018, the Company opted to make use of its self-supply capacity, during the term of SE Resolution No. 70/18, and has destined a significant part of its natural gas production to its thermal units’ dispatch (see Note 2.1.5).

From December 30, 2019, with the abrogation of SE Resolution No. 70/18, 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 a term of 4 years.

In addition to GasAr Plan, in 2021 CAMMESA continued calling for tenders on a monthly basis, at a maximum price of US$ 2.3/MBTU until April and US$ 3.5 until August, on an interruptible basis for GasAr Plan awardees and under a 30% DOP clause for the rest. However, from September 2021 these calls were declared unawarded. Moreover, 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 I. In 2021, an average of 25.2 million m3/day were awarded at a price of US$ 3.4/MBTU.

2.2.2.4 Natural Gas Exports

The procedure for the authorization of natural gas exports established by SE Resolution No. 417/19 —with the security of supply to the Argentine domestic market being a condition in all cases— was in effect until the end of April 2021. It is worth mentioning that the exported volume did not qualify for calculating the incentive for domestic production increase encouragement programs.

Under this proceeding, in November 2020 the Company was granted permits to export gas to different customers in Chile on an interruptible basis, expiring between April 2021 and January 2022.

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 I. 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.

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, stipulated 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%.

2.2.2.5 “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, this resolution created the “TransportAr Production Gas Pipelines System Program” (the “Program”) to execute the works necessary to expand the system’s transportation capacity and to promote development, production growth, and natural gas self-supply, among other objectives. The Program included a list of pipeline works to be executed by IEASA or through third parties.

Later, DNU No. 76/22, published on February 14, 2022, granted IEASA a 35-year transportation concession of President Néstor Kirchner pipeline under Law No. 17,319.

Moreover, IEASA, as principal, was granted the power to contract, plan, execute and call for tenders for the construction of the infrastructure works under the Program. IEASA may enter into transportation capacity freely-negotiated agreements with producers and/or carriers to construct or expand all or part of the pipeline. This transportation capacity will not be covered by tariffs approved by ENARGAS, which will apply to the remaining transportation capacity not committed under these agreements. This DNU grants YPF priority to hire the capacity that can be freely negotiated by IEASA. Moreover, IEASA may fully or partially assign ownership of its concession to YPF.

Besides, the “Argentine Gas Development Fund” administrative and financial trust was created, with IEASA as trustor and beneficiary, to finance works under the Program, including the repayment of principal and interest services of the trust securities to be issued thereunder. The trust estate administrator and trustee will be Banco de Inversión y Comercio Exterior S.A.

2.2.3 Oil market

2.2.3.1 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 recognized when the reference price equals or exceeds US$ 60/bbl. Since February 2021, the rate has remained at 8%.

2.2.3.2 Hydrocarbon exploration and exploitation levy

Law No. 27,007 set the levy values per km2 or fraction to be paid annually and in advance by the permit holder. Exploitation permits will amount to $ 4,500 and exploration permits, to $ 250 in the first period, $ 1,000 in the second period of the basic term, and $ 17,500 during the first year of the extension (with a 25% annual cumulative increase). It is worth highlighting that up to 10% of the levy value payable in the second period of the basic term and the extension may be offset with actual investments per km2.

On September 26, 2019, the Province of Neuquén, pursuant to Provincial Executive Order No. 2,032/19, published new levy values per km2 or fraction effective for this province from 2020. The exploitation levy was set at $ 22,410, and the exploration levy at $ 1,245 for the first period, $ 4,980 for the second period, $ 7,470 for the third period, and $ 87,150 for the extension period.

From 2021, PEN Executive Order No. 771/20 set a maximum levy in pesos equivalent to a certain volume of oil at the average price for the semester before settlement, at BNA’s exchange rate effective on the last business day before payment.

This scheme is applicable nationwide (including the Province of Neuquén, which acceded to it under Provincial Executive Order No. 1,656/20). Exploitation permits amount to 8.28 barrels and exploration permits to 0.46 barrels in the first period, 1.84 barrels in the second period of the basic term, and 32.22 barrels in the extension period.

2.3 Gas Transportation

2.3.1 TGS’s Tariff situation

On March 30, 2017, within the framework of the tariff renegotiation process, TGS executed the 2017 Integral Agreement which, after being approved by the different intervening government agencies and the National Congress, was ratified on March 27, 2018, through PEN Decree No. 250/18. This decree represents the conclusion of the RTI process and terminates all transitional agreements celebrated by TGS, and thus, the final renegotiation of the license after seventeen years of negotiations.

The 2017 Integral Agreement sets 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 WPI 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 WPI 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 WPI, 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 WPI 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.

Subsequently, the Solidarity Law provided that natural gas transportation and distribution tariffs would remain unchanged for a term of 180 days as from December 23, 2019. In this sense, the PEN is vested with the power to renegotiate them, whether under the current RTI or through an extraordinary review pursuant to the provisions of the Natural Gas Law.

On June 9, 2020, pursuant to Resolution No. 80/20, the ENARGAS created the Coordination and Centralization Committee —Act No. 27,541 and Executive Order No. 278/20— with the mission of coordinating the Integral Tariff Structure Review provided for in section 5 of the Solidarity Law.

On June 19, 2020, the PEN issued Executive Order No. 543/20 provided that natural gas transportation and distribution tariffs would remain unchanged for an additional term of 180 calendar days, that is, until December 16, 2020.

By provision of the Emergency Executive Order No. 1,020/20, the ENARGAS, commissioned by the PEN, launched the renegotiation of the RTI finished in 2018, which may not exceed a term of 2 years. Until then, renegotiation agreements in force are suspended. The renegotiation will be conducted by ENARGAS ad referendum to the PEN.

Furthermore, Executive Order No. 1,020/20 extends the tariff freeze for an additional term of 90 calendar days or until the approval of the transitory tariffs. It is worth highlighting that all the agreements, whether transitory or general, entered into with the Federal Government will have to contemplate the public hearing proceedings established by the current regulations and be authorized by the different governmental bodies.

Additionally, the Solidarity Law and Decree No. 1,020/20 provide for the administrative intervention of the ENARGAS.

The public hearing called by ENARGAS to discuss the RTT pursuant to the provisions of Executive Order No. 1,020/20 took place on March 16, 2021. In this respect, TGS, without waiving the whole of its percentage share of tariff recomposition, alternatively submitted in the hearing its tariff increase proposal, assessed at 58.6% as from April 1, 2021. This increase was assessed based on the financial needs to meet operating and financial costs, capital expenditures and taxes, which were calculated taking into consideration the evolution of the inflation rate over a 12-month period as from its beginning. The requested increase only contemplates 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 pursuant to Executive Order No. 1,020/20, 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 2021 Transitional Agreement Project.

Later, on June 2, 2021, ENARGAS issued Resolution No. 149/21 approving an RTT 2021 for TGS effective as from that date and under the same terms of the project timely submitted on April 28, 2021.

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 a DNU, 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 Executive Order No. 1020/20. In this hearing, aiming to reach a final renegotiation 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 a 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 includes certain terms similar to the RTT 2021, with the specific provision that it grants TGS a 60% tariff increase effective from March 1, 2022.

The RTT 2022 was ratified by the PEN through 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.

As of the issuance of these Financial Statements, TGS is working jointly with ENARGAS to conduct the RTI process that will allow the company to receive a fair and reasonable tariff in line with the provided natural gas transportation utility service.

2.3.2 Regulatory framework of the segment of Production and Marketing of Liquids

2.3.2.1 Domestic market

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

GLP domestic sales prices are impacted by the provisions of Law No. 26,020 "Regime of the industry and commercialization of liquefied petroleum gas" and the Argentine Government through the public office in charge, that set forth LPG minimum volumes to be sold in the local market in order to guarantee domestic supply.

In this context, TGS sells the production of propane and butane to fractionators at prices determined semiannually by the SRH. 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 marketing chain in order to guarantee the supply to low-income residential user, by committing the GLP producers to supply at a fixed price with a quota assigned to each producer. Additionally, payment of compensation to the Household Plan participating producers was established.

Executive Order No. 311/20, set maximum reference prices for the sale of LPG, which TGS sells in the domestic market, remained unchanged for a term of 180 calendar days as from its issuance in march 2020. On October 19, 2020, the SE passed Resolution No. 30/20 increasing the price of these products to $ 10,885, and in 2021, the SE passed Resolution No. 249/2021, increasing prices to $ 12,626.60 from April 6, 2021.

In this context, 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 by which it undertakes to supply propane to the domestic market 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, 2021, the Argentine Government owes TGS $ 1,246,168 under these items.

2.3.2.2 Foreign market

Executive Order No. 488/20 regulated the rate applicable to the export duties for certain gas and oil derivatives, including the products produced and exported by TGS, which ranges between 0% and 8% depending on the price of the “ICE Brent first line” barrel. If this price is below US$ 45, the rate is 0%. Instead, if the price equals or exceeds US$ 60, an 8% rate is paid, and the rate is variable if the price is between US$ 45 and US$ 60.

2.4 Transmisión

2.4.1 Transener and Transba tariff situation

The Solidarity Law, which entered into effect on December 23, 2019, provided that electricity tariffs under federal jurisdiction would remain unchanged, and contemplates the possibility to perform an extraordinary review of the current RTI for a maximum term of up to 180 days.

In 2020, the ENRE did not apply Transener’s semi-annual tariff update mechanism established in the RTI, being the tariff scheme in force the one resulting from the August 2019 update.

In this sense, on December 16, 2020, pursuant to Executive Order No. 1020/20, the Federal Government established the beginning of the renegotiation of the current RTI for the electricity and natural gas transportation and distribution utility services, which proceeding may not exceed a term of 2 years. Until the conclusion of each renegotiation, all Agreements corresponding to the respective RTIs in effect will be suspended within the scopes determined in each case by the Regulatory Entities for reasons of public interest. The transitory and final agreements will be entered into with the ENRE or ENARGAS, and the Ministry of Economy ad referendum to the PEN. Furthermore, the electricity tariffs maintenance term established in section 5 of Law No. 27,541 on Social Solidarity and Productive Reactivation within the Public Emergency Framework was extended for 90 calendar days, or until the entry into effect of the new transitory tariff schemes resulting from the RTT.

On January 19, 2021, through Resolution No. 17/21, the ENRE launched the proceeding for the transitory adjustment of tariffs of the transmission public utility aiming to establish a RTT until reaching a Final Renegotiation Agreement, and summoning Transportation Companies. In this sense, a request for the information necessary to begin this process was received, and Transener has complied with this requirement, prioritizing the operating costs and capital expenditures required to maintain service quality.

On March 3, 2021, pursuant to Resolutions No. 54/21 and 55/21, the ENRE called for a Public Hearing for March 29, 2021 to provide information and gather feedback on the RTT for Transener and Transba, respectively, within the RTI Process and prior to the definition of tariffs.

On April 14, 2021 the Public Hearing Closing Report was published in the BO, continuing the negotiations with the ENRE in order to reach a RTT for the RTI.

On January 26, 2022, Resolution No. 25/22 was published in the BO, through which the ENRE convened a new public hearing on February 17, 2022 in order to discuss, among other issues, the proposal for transportation companies for the transitory adjustment of tariff, that were unchanged since August 2019.

On February 25, 2022, the ENRE issued Resolutions No. 68/22 and 69/22, which approves the new hourly remuneration, effective as from February 1, 2022, establishing an increase of 25% and 23% with respect to remuneration effective as from August 2019, for Transener and Transba, respectively. Considering the difference between the financial economic projections presented and the remuneration finally approved by the ENRE, a request for a view of the file and a preliminary challenge were submitted. In addition, both resolutions will be appealed by Transener and Transba.

Besides, on July 3, 2018 the ENRE informed of the launching of the proceeding for the determination of the remuneration of Independent Transmission Companies in the exploitation stage: TIBA (Transba), the Fourth Line (Transener), YACYLEC and LITSA. In this respect, on October 8, 2018, information on costs, investments and tariff claims corresponding to the Fourth Line and TIBA were submitted to the ENRE. As of issuance of these Consolidated Financial Statements, the ENRE has not issued a resolution with the results of the analysis of the requested information.

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, among other factors, with transactions with stock market assets by companies and the disposal of liquid foreign assets.

In early 2021, the BCRA provided for a series of measures aiming to ease access to the MLC, specifically to: (i) favor the exchange or financing of foreign private-sector liabilities entered and settled through the MLC and concerted as from January 7, 2021, (ii) transfer foreign currency abroad as earnings and dividends to non-resident shareholders, as from the second anniversary of the investment, for transactions entered and settled through the MLC and destined to the financing of projects under GasAr Plan (see Note 2.2.2.1.2), among other issues. However, the BCRA later extended the validity of the measures established in 2020 and adopted new restrictions to access the MLC.

In this sense, it remains in force the obligation to file an affidavit to access the MLC in terms of expenditures without BCRA’s prior authorization, certifying that all foreign-currency holdings in the country are deposited in accounts with local financial institutions and that it have liquid foreign assets available was requested for an amount equivalent to or higher than US$ 100,000. In case such liquid foreign assets exceed the amount of US$ 100,000, but include reserve or guarantee funds created under debt contracts or transactions with derivatives entered into abroad and that may not be used, an additional affidavit should be submitted. To such effects, the term “liquid foreign assets” will comprise, among others: holdings of foreign currency notes and coins, availability of gold in the form of good delivery bars or coins, sight deposits in foreign financial entities and other investments allowing for the immediate availability of foreign currency (for example, investments in foreign public securities, funds in investment accounts deposited with investment managers located abroad, crypto assets, funds deposited in payment service providers’ accounts, etc.). On the other hand, the following will not be considered available liquid foreign assets: funds deposited abroad which may not be used by the customer as they are reserve or guarantee funds created under foreign debt contracts, or funds kept as collateral for foreign transactions with derivatives entered into abroad.

Furthermore, it is maintained the obligation to enter and settle in the MLC, in case access has been requested and within a term of five business days after they become available, foreign funds originating from the collection of loans granted to third parties, the collection of time deposits or the sale of any kind of asset, in case the asset has been acquired, the deposit has been made or the loan has been granted after May 28, 2020.

As regards transactions with stock market assets, restrictions on exchange transactions and the acquisition of securities issued by non-residents were extended, providing as follows: (i) the restriction, as from the moment access to the MLC is requested, to sell in the country securities issued by residents involving settling in foreign currency or exchanging securities issued by residents for foreign assets or their transfer to depository institutions abroad, or the acquisition in the country involving settlements in pesos of securities issued by non-residents for a term of 90 days before and after the request, and the filing of an affidavit in this respect; and (ii) that security transactions concerted abroad and securities acquired abroad may not be settled in pesos in the country. Moreover, if the customer is a legal entity, as an additional requirement to access the MLC, it also provided for an additional affidavit stating: (a) details of the individuals or legal entities exercising a direct control relationship over the customer, according to BCRA’s regulations; and (b) that on the day access to the MLC is requested and in the previous 90 calendar days, no local-currency funds or other liquid domestic assets have been delivered in Argentina to any individual or legal entity exercising a direct control relationship over it, except for those directly associated with regular transactions for the acquisition of goods and/or services. The requirement stated in item (b) will be deemed duly met if the customer submits an affidavit regarding transactions with securities of each individual or legal entity pursuant to the current exchange regulations.

Regarding imports, BCRA’s prior authorization to access the MLC is required to make payments to import certain goods abroad or cancel the principal of debts originating from the import of goods by companies. Additionally, before executing payments for the import of goods, entities should verify that the affidavit requested from the customer is compatible with BCRA’s existing data. Besides, the need for BCRA’s prior authorization to access the MLC was extended until June 30, 2022 inclusive in the following cases: (i) the cancellation of principal of foreign financial debts with foreign affiliates, and (ii) payments for the import of certain goods, unless certain conditions are met, such as the presentation of an affidavit by the customer declaring that the total amount of payments associated with the goods imports transacted through the MLC does not exceed US$ 250 thousand; or in the case of a deferred payment for the import of goods for transactions shipped from July 1, 2020, or which, having been previously shipped, had not arrived in the country before that date; or a sight payment or payment of commercial debts without a customs entry registration for the import of supplies to manufacture goods in the country.

Furthermore, the BCRA extended the obligation to submit a refinancing plan for certain debts and principal maturities scheduled until June 30, 2022, based on the following criteria: (i) access to the MLC for up to 40% of the principal amount, within the original term; and (ii) the refinancing of the principal balance, through new foreign indebtedness with an average life of 2 years. Within the framework of this refinancing process, access to the MLC is allowed for the early cancellation of principal, interest or debt swaps up to 45 calendar days before the maturity date, provided all requirements set forth by the regulation have been verified.

Additionally, the BCRA created a registry of foreign exchange information of goods exporters and importers as a requirement to access the MLC to perform forex outflow transactions, including swaps and arbitrations. The Company has been declared an obliged subject by the BCRA; it has completed its enrollment in this registry and is under a duty to report any change in the recorded information within 15 business days of its occurrence.

Finally, the BCRA extended, under the same definitions and conditions, the “Certification of increased exports of goods in 2021” for exporters of goods registering increases in 2022 compared to 2021. In the case of imports, as an additional requirement to access the MLC for the payment of services rendered by non-residents, it incorporated the presentation of a new affidavit made through the Integral Monitoring System for Payments to Foreign Payments for Services (SIMPES), except for certain transactions (freight services, governmental services, etc.).

More information on Argentina’s foreign exchange regulations can be found at the Central Bank’s website: www.bcra.gov.ar.

2.6 Tax regulations - Main tax reforms

Pursuant to Act No. 27,430 and Act No. 27,541, 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, Act No. 27,630 was published in the BO, which modified the income tax rate effective for fiscal years starting as from January 1, 2021 inclusive. This modification provides for the application of a tiered rate scheme and, if applicable, a fixed tax according to the accumulated net taxable income tier: (i) for accumulated net income of up to $ 5 million, it establishes a 25% rate; (ii) for accumulated net income between $ 5 and $ 50 million, it establishes a fixed tax of $1.25 million plus a 30% rate over the surplus of $ 5 million; and (iii) for accumulated net income above $ 50 million, it establishes a fixed tax of $ 14.75 million plus a 35% rate over the surplus of $50 million. The accumulated net income amount will be adjusted yearly, as from January 1, 2022, taking into consideration the annual CPI variation published by the INDEC.

The effect of the application of the income tax rate changes on deferred tax assets and liabilities pursuant to the above-mentioned tax reform was recognized, based on their expected 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).

2.6.1.2 Tax on dividends

According to Law No. 27,430, the tax on dividends or earnings distributed by, among others, Argentine companies or permanent establishments to individuals, undivided estates or beneficiaries residing abroad is introduced based on the following considerations: (i) dividends resulting from earnings accrued during fiscal years beginning as from January 1, 2018 until December 31, 2019, are subject to a 7% withholding; and (ii) dividends resulting from earnings accrued during fiscal years beginning as from January 1, 2020 would be subject to a 13% withholding.

However, due to the modifications introduced by Law No. 27,541 and Law No. 27,630, the 7% withholding rate remains unchanged for fiscal years beginning as from January 1, 2020.

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 IPC 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 one hundred percent (100%) over the thirty-six (36) months preceding the closing of the fiscal period to be settled; alternatively, for the first, second and third fiscal year as from its effective date, this proceeding will apply in case the accumulated variation in such price index, calculated from the beginning of the first fiscal year to the closing of each fiscal year, are higher than fifty-five percent (55%), thirty percent (30%) and fifteen percent (15%) for the years 2018, 2019 and 2020, respectively.

Law No. 27,541 provides 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 (1/6) should be charged in that fiscal period and the remaining five sixths (5/6), in equal parts, in the five immediately following fiscal periods.

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 taking into consideration the annual guideline established by Act No. 27,430 (see Note 10.6).

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.