| REGULATORY FRAMEWORK | 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:
Schedule of remuneration for thermal generators with guaranteed power capacity
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:
Schedule of hydroelectric generators by technology and scales values
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:
Schedule of generated
and operated energy thermal units remuneration
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:
Schedule
of generated and operated energy hydroelectric units remuneration
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 $/MVAr are recognised under SE Resolution No. 440/21, No. 238/22, No. 826/22 and 869/23, respectively, for the megavolt-amperes
exchanged with the grid when required, in addition to the prices for operated energy. As regards energy generated from
unconventional sources, a single remuneration value was set irrespective of the source used:
Schedule of unconventional sources remuneration
Remuneration
SE No. 440/21 ($ / 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:
Schedule of additional remuneration to thermal generators
Period SE No. 440/21 SE No. 238/22
First 25 hours ($ / MW-hmrt)
Second 25 hours ($ / MW-hmrt)
First 25 hours ($ / MW-hmrt)
Second 25 hours ($ / MW-hmrt)
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
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
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 5 35 15 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
- Unconventional exploration
- Continental shelf and off-shore exploitation
(ii) Sets the terms for exploitation concessions, extensible for 10-year terms:
- Conventional exploitation concession
- Unconventional exploitation concession
- Continental shelf and off-shore exploitation concession
(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-" id="sjs-B4">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:
Schedule of generating units in operation
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)
Schedule of generating units in construction
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 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 10 25 28 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 28 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:
Schedule of minimum remuneration to thermal generators
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:
Schedule of remuneration for thermal generators with guaranteed power capacity
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:
Schedule of hydroelectric generators by technology and scales values
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:
Schedule of generated
and operated energy thermal units remuneration
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:
Schedule
of generated and operated energy hydroelectric units remuneration
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 $/MVAr are recognised under SE Resolution No. 440/21, No. 238/22, No. 826/22 and 869/23, respectively, for the megavolt-amperes
exchanged with the grid when required, in addition to the prices for operated energy. As regards energy generated from
unconventional sources, a single remuneration value was set irrespective of the source used:
Schedule of unconventional sources remuneration
Remuneration
SE No. 440/21 ($ / 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:
Schedule of additional remuneration to thermal generators
Period SE No. 440/21 SE No. 238/22
First 25 hours ($ / MW-hmrt)
Second 25 hours ($ / MW-hmrt)
First 25 hours ($ / MW-hmrt)
Second 25 hours ($ / MW-hmrt)
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
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
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 5 35 15 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
- Unconventional exploration
- Continental shelf and off-shore exploitation
(ii) Sets the terms for exploitation concessions, extensible for 10-year terms:
- Conventional exploitation concession
- Unconventional exploitation concession
- Continental shelf and off-shore exploitation concession
(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- |
