Pampa Energía S A : CONSOLIDATED FINANCIAL STATEMENTS AS OF DECEMBER 31, 2023 AND 2022 FOR THE YEARS ENDED DECEMBER 31, 2023, 2022 AND 2021 - Form 6-K

CONSOLIDATED FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2023 AND 2022

FOR THE YEARS ENDED DECEMBER 31, 2023, 2022 AND 2021

(In millions of U.S. dollar ("US$"))

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of

Pampa Energía Sociedad Anónima (Pampa Energía S.A.)

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated statement of financial position of Pampa Energía Sociedad Anónima (Pampa Energía S.A.) and its subsidiaries (the "Company") as of December 31, 2023 and 2022, and the related consolidated statements of comprehensive income, of changes in equity and of cash flows for each of the three years in the period ended December 31, 2023, including the related notes (collectively referred to as the "consolidated financial statements"). We also have audited the Company's internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 in conformity with IFRS Accounting Standards as issued by the International Accounting Standards Board. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting included under Exhibit 99.3. Our responsibility is to express opinions on the Company's consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Price Waterhouse & Co. S.R.L., Bouchard 557, 8^th floor, C1106ABG - Autonomous City of Buenos Aires, Argentina

T: +(54.11) 4850.0000, www.pwc.com/ar

Definition and Limitations of Internal Control over Financial Reporting

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

The Impact of Proved Estimates of Oil and Gas Reserves on Oil and Gas Segment Property, Plant and Equipment and Allocated Goodwill.

As described in Notes 7 and 11.2 to the consolidated financial statements, as of December 31, 2023, the Company's consolidated net book value of property, plant and equipment balance of the oil and gas segment was US$ 1.138 million, the goodwill balance allocated to the oil and gas segment was US$ 35 million, and depreciation expense for the year ended December 31, 2023 was US$ 166 million. As described in Note 6.1.7 to the consolidated financial statements, the Company's management estimates oil and gas reserves which are used in the determination of depreciation of property, plant and equipment used in the areas of oil and gas, as well as assessing the recoverability of these assets and goodwill allocated to the oil and gas segment. There are numerous uncertainties in estimating proved and unproved reserves and future production profiles, development costs and prices, including several factors beyond the producer's control. Reserve engineering is a subjective process of estimating underground accumulations involving a certain degree of uncertainty. Reserves estimates depend on the quality of the available engineering and geological data as of the estimation date and on the interpretation and judgment thereof. Periodic revisions to the estimated oil and gas reserves and related future net cash flows may be necessary as a result of changes in a number of factors, related to reservoir performance, new drilling, oil and gas prices, cost, technological advances, new geological or geophysical data, and other economic factors. The estimates of oil and gas reserves have been developed by employed specialists, specifically petroleum engineers, and audited by independent specialists engaged by the Company.

The principal considerations for our determination that performing procedures relating to the impact of estimates of proved oil and gas reserves on oil and gas segment property, plant and equipment and allocated goodwill are a critical audit matter are the significant judgment by management, including the use of specialists, when developing the estimates of oil and gas reserves, which in turn led to a high degree of auditor judgment and effort in performing procedures to evaluate the significant assumptions used in developing those estimates, related to future production profiles, development costs and prices.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management's estimates of oil and gas reserves. These procedures also included, among others, evaluating the methods and significant assumptions used by management in developing these estimates, related to future production profiles, development costs and prices. The work of management's engaged specialist was used in performing the procedures to evaluate the reasonableness of these estimates of proved oil and gas reserves. As a basis for using this work, the specialists' competence, capability and objectivity were understood, as well as their methods and assumptions. The procedures performed also included tests of the data used by the Company's engaged specialists and an evaluation of their findings. Evaluating the significant assumptions relating to the estimates of proved oil and gas reserves also involved obtaining evidence to support the reasonableness of the assumptions, including whether the assumptions used were reasonable considering the past performance of the Company, and whether they were consistent with evidence obtained in other areas of the audit. The procedures performed also included testing that the estimates of oil and gas reserves were appropriately included in the Company's determination of depreciation expense, as well as in the impairment of non-financial assets assessment of oil and gas segment.

Impairment of Non-Financial Long-Lived Assets Related to the Rincón del Mangrullo and el Tordillo / la Tapera cash generating units within the Oil and Gas Segment

As described in Note 7 to the consolidated financial statements, as of December 31, 2023, the Company's consolidated property, plant and equipment balance of the oil and gas segment was US$ 1.138 million. According to Notes 6.1.1. and 11.1.1, as of December 31, 2023 there were internal and external impairment indicators in relation to Rincón del Mangrullo and el Tordillo / la Tapera cash generating units (CGUs). Management analyzes the recoverability of its non-financial long-lived assets on a periodic basis or when events or changes in circumstances indicate their recoverable amount may be below their carrying amounts. In order to evaluate if there is evidence that a CGU could be affected, both external and internal sources of information are analyzed. The recoverable amount is the higher of value in use and fair value less costs of disposal. Management used value in use to determine the recoverable amount. The value in use is determined based on the present value of future net cash flows expected to be derived from the CGU, using discount rates that considers the business segment and the economic conditions in the geographical location of the operations. Management's assessment of the existence of impairment indicators and cash flow projections included key judgments and assumptions relating to reference prices for products, future demand per type of product, costs evolution, macroeconomic variables such as inflation and exchange rates and the discount rate.

The principal considerations for our determination that performing procedures relating to the impairment of non-financial long-lived assets related to the Rincón del Mangrullo and el Tordillo / la Tapera CGUs within the oil and gas segment is a critical audit matter are the key judgment by management when evaluating the existence of impairment indicators and when developing the recoverable value measurement of the non-financial long-lived assets. This in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures to evaluate management's assessment of impairment indicators and cash flow projections and key assumptions related to reference prices for products, future demand per type of product, costs evolution, macroeconomic variables such as inflation, exchange rates and the discount rate. In addition, the audit effort involved the use of professionals with specialized skill and knowledge to assist us in performing these procedures and evaluating the audit evidence obtained.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management's impairment assessment, including controls over the valuation of the Company's non-financial long-lived assets. These procedures also included, among others, evaluating the determination of the Company's CGUs, as well as the allocation of the assets and liabilities thereto; evaluating the reasonableness of management's assessment over the existence of impairment indicators; testing management's process for developing the value in use estimate; evaluating the appropriateness of the discounted cash flow model, as well as the mathematical precision of the calculations; testing the completeness, accuracy, and relevance of underlying data used in the model; and evaluating the key assumptions used by management related to reference prices for products, future demand per type of product, costs evolution, macroeconomic variables such as inflation and exchange rates, and the discount rate. Evaluating management's assumptions involved evaluating whether the assumptions used by management were reasonable considering (i) the current and past performance of the CGUs, (ii) the consistency with external market and industry data, and (iii) whether these assumptions were consistent with evidence obtained in other areas of the audit. Professionals with specialized skill and knowledge were used to assist in the evaluation of the Company's discounted cash flow model and the discount rate. The procedures performed also included evaluating the sufficiency of the information disclosed in the consolidated financial statements regarding the evaluation of the recoverable value of long-lived non-financial assets.

Acquisition of additional interest in Rincón de Aranda and divestment in Greenwind S.A. - fair value determination of assets acquired and liabilities assumed

As described in Notes 4.4.5 and 5.2.6 to the consolidated financial statements, on August 16, 2023, the Company completed the acquisitions of the additional 45% interest in the Rincón de Aranda block, achieving a 100% interest in the block and, as part of the agreement, transferred 100% of its equity stake in Greenwind S.A., which only asset is the Mario Cebreiro Wind Farm. On the closing date, the Company determined the fair value of the assets acquired and liabilities assumed, which amounted US$ 85.8 million, and recorded a gain of US$ 6.6 million to reflect the fair value of the previously held 55% stake in the Rincón de Aranda block, as well as a gain of US$ 0.2 million to reflect the result of the asset swap. The Company's management applied significant judgment in estimating the fair value of the assets acquired and liabilities assumed, which involved the use of key estimates and assumptions with respect to reference prices for products, future demand per type of product, costs evolution and macroeconomic variables such as inflation, exchange rates and the discount rate.

The principal considerations for our determination that performing procedures relating to the acquisition of additional interest in Rincón de Aranda and divestment in Greenwind S.A. - fair value determination of assets acquired and liabilities assumed is a critical audit matter are: (i) the key judgment by management in developing the fair value of the assets acquired and liabilities assumed, which in turn led to a high degree of auditor judgment and subjectivity in applying procedures relating to management's fair value estimate; (ii) the significant audit effort in evaluating management's key assumptions related to reference prices for products, future demand per type of product, costs evolution and macroeconomic variables, such as inflation, exchange rates and the discount rate; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to acquisition accounting, including controls over management's valuation of the fair value of assets acquired and liabilities assumed and controls over development of the assumptions related to reference prices for products, future demand per type of product, costs evolution and macroeconomic variables such as inflation, exchange rates and the discount rate. These procedures also included, among others, (i) reading the purchase agreement; (ii) testing management's cash flow projections used to estimate the fair value of assets acquired and liabilities assumed, which included evaluating the reasonableness of key assumptions used by management related to reference prices for products, future demand per type of product, costs evolution and macroeconomic variables such as inflation, exchange rates and the discount rate. Evaluating management's assumptions involved evaluating whether the assumptions used by management were reasonable considering (i) the current and past performance of the acquired business, (ii) the consistency with external market and industry data, and (iii) whether these assumptions were consistent with evidence obtained in other areas of the audit. Professionals with specialized skill and knowledge were used to assist in evaluating the appropriateness of valuation method and the reasonableness of the discount rate. The discount rate was evaluated by considering the cost of capital of comparable businesses and other industry factors. The procedures performed also included evaluating the sufficiency of the information disclosed in the consolidated financial statements regarding business combination.

/s/ PRICE WATERHOUSE & CO. S.R.L.

/s/ Carlos Martin Barbafina (Partner)

Autonomous City of Buenos Aires, Argentina, March 6, 2024.

We have served as the Company's auditor since 2006.

GLOSSARY OF TERMS

The following are not technical definitions, but they are helpful for the reader's understanding of some terms used in the notes to the Consolidated Financial Statements of the Company.

Terms	Definitions
ADR	American Depositary Receipt
AFIP	Federal Administration of Public Revenue
BCBA	Buenos Aires Stock Exchange
BCRA	Argentina's Central Bank
BNA	Banco de la Nación Argentina
BO	Official Gazette
CAMMESA	Compañía Administradora del Mercado Eléctrico Mayorista S.A.
CB	Corporate Bonds
CC	Combined Cycle
CENCH	Hydrocarbons Unconventional Exploitations Concessions
CGU	Cash-Generating Unit
CIESA	Compañía de Inversiones de Energía S.A.
CISA	Comercializadora e Inversora S.A
Citelec	Compañía Inversora en Transmisión Eléctrica Citelec S.A.
CNV	National Securities Commission of Argentina
CPB	Piedra Buena thermal power plant
CPI	Consumer's price index
CSJN	Argentina' Supreme Court of Justice
CTB	CT Barragán S.A.
CTEB	Ensenada Barragán thermal power plant
CTG	Güemes thermal power plant
CTGEBA	Genelba thermal power plant
CTIW	Ingeniero White power plant
CTLL	Loma La Lata thermal power plant
CTPP	Parque Pilar power plant

GLOSSARY OF TERMS: (Continuation)

Terms	Definitions
EcuadorTLC / PB18	EcuadorTLC S.A. (currently Pampa Bloque 18)
Edenor	Empresa Distribuidora y Comercializadora Norte S.A.
EMESA	Empresa Mendocina de Energía S.A.
ENARGAS	National Regulator of Gas
ENARSA	Energía Argentina S.A.
ENRE	National Regulatory Authority of Electricity
GASA	Generación Argentina S.A.
Greenwind	Greenwind S.A.
GU	Large users
GU300	Large users with demand greater than 300 kW
GUDI	Distributors' large users
GUMA	Major large users
GUME	Minor large users
HI	Hydroelectric
HIDISA	Hidroeléctrica Diamante S.A.
HINISA	Hidroeléctrica Los Nihuiles S.A.
HPPL	Hidroeléctrica Pichi Picún Leufú
IAS	International Accounting Standards
IASB	International Accounting Standards Board
IFRIC	International Financial Reporting Interpretations Committee
IFRS	International Financial Reporting Standards
INDEC	National Institute of Statistics and Censuses
IPIM	Wholesale Domestic Price Index
LGS	Argentine Business Organizations Law
LNG	Liquefied Natural Gas
MAT	WEM's Forward Market
MATER	Renewable Energy Forward Market

GLOSSARY OF TERMS: (Continuation)

Terms	Definitions
MBTU	Million of BTU
MEyM	Ministry of Energy and Mining
MLC	Foreign Exchange Market
MVAr	Reactive kilovolt-ampere
MW	Megawatt
NYSE	New York Stock Exchange
OCP	Oleoductos de Crudos Pesados Ltd
OCPSA	Oleoductos de Crudos Pesados S.A.
Oldelval	Oleoductos del Valle S.A.
PE Arauco	Arauco Wind Farm
PEB	Pampa Energía Bolivia S.A.
PEN	Federal Executive Branch
PEPE II	Pampa Energía II Wind Farm
PEPE III	Pampa Energía III Wind Farm
PEPE IV	Pampa Energía IV Wind Farm
PEPE VI	Pampa Energía VI Wind Farm
PISA	Pampa Inversiones S.A.
Refinor	Refinería del Norte S.A.
RTI	Tariff Structure Review
RTT	Transitional Tariff Regime
SACDE	Argentine Society of Construction and Strategic Development
SE	Secretary of Energy
SEC	Security and Exchange Commission
TG	Gas Turbine
TGS	Transportadora de Gas del Sur S.A.
The Company / Pampa	Pampa Energía S.A.

GLOSSARY OF TERMS: (Continuation)

Terms	Definitions
The Group	Pampa Energía S.A. and its subsidiaries
TJSM	Termoeléctrica José de San Martín S.A.
TMB	Termoeléctrica Manuel Belgrano S.A.
Transba	Empresa de Transporte de Energía Eléctrica por Distribución Troncal de la Provincia de
Transener	Compañía de Transporte de Energía Eléctrica en Alta Tensión Transener S.A.
TV	Vapor Turbine
US$	U.S. dollar
VAR	Vientos de Arauco Renovables S.A.U.
VAT	Value Added Tax
VS SLU	Vientos Solutions S.L.U.
WACC	Weighted Average Cost of Capital
WEM	Wholesale Electrical Market
YPF	YPF S.A.
$	Argentine Pesos

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

For the years ended December 31, 2023, 2022 and 2021

(In millions of US$ - unless otherwise stated)

	Note			12.31.2023		12.31.2022		12.31.2021
Revenue	8			1,732		1,829		1,508
Cost of sales	9			(1,107)		(1,139)		(951)
Gross profit				625		690		557
Selling expenses	10.1			(66)		(65)		(37)
Administrative expenses	10.2			(185)		(142)		(102)
Exploration expenses	10.3			(7)		-		-
Other operating income	10.4			177		131		105
Other operating expenses	10.4			(88)		(46)		(58)
Impairment of property, plant and equipment, intangible assets and inventories			(39)		(38)		(4)
(Impairment) Recovery of impairment of financial assets				-		(4)		1
Share of profit from associates and joint ventures	5.3.2			(2)		105		100
Profit from sale/acquisition of companies´ interest				9		-		17
Operating income				424		631		579
Financial income	10.5			5		5		10
Financial costs	10.5			(364)		(221)		(185)
Other financial results	10.5			558		166		(14)
Financial results, net				199		(50)		(189)
Profit before income tax				623		581		390
Income tax	10.6			(318)		(124)		(77)
Profit of the year from continuing operations				305		457		313
Loss of the year from discontinued operations	5.2.1			-		-		(75)
Profit of the year				305		457		238
Other comprehensive income (loss)
Items that will not be reclassified to profit or loss
Results related to defined benefit plans				(5)		(9)		(3)
Income tax				2		3		1
Exchange differences on translation				(78)		21		22
Items that may be reclassified to profit or loss
Exchange differences on translation				(97)		39		70
Other comprehensive (loss) income of the year from continuing operations				(178)		54		90
Other comprehensive income of the year from discontinued operations	5.2.1			-		-		64
Other comprehensive (loss) income of the year				(178)		54		154
Total comprehensive income of the year				127		511		392

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (Continuation)

For the years ended December 31, 2023, 2022 and 2021

(In millions of US$ - unless otherwise stated)

	Note			12.31.2023		12.31.2022		12.31.2021
Total income (loss) of the year attributable to:
Owners of the company				302		456		273
Non-controlling interest				3		1		(35)
				305		457		238
Total income (loss) of the year attributable to owners of the Company:
Continuing operations				302		456		312
Discontinued operations				-		-		(39)
				302		456		273
Total comprehensive income (loss) of the year attributable to:
Owners of the Company				124		510		393
Non-controlling interest				3		1		(1)
				127		511		392
Total comprehensive income (loss) of the year attributable to owners of the Company:
Continuing operations				124		510		402
Discontinued operations				-		-		(9)
				124		510		393
Earnings (Loss) per share attributable to equity holders of the Company
Basic and diluted earnings per share from continuing operations	13.2			0.22		0.33		0.22
Basic and diluted loss per share from discontinued operations	13.2			-		-		(0.03)
Total basic and diluted earning per share	13.2			0.22		0.33		0.19

The accompanying notes are an integral part of these Consolidated Financial Statements.

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

As of December 31, 2023 and 2022

(In millions of US$ - unless otherwise stated)

	Note		12.31.2023		12.31.2022
ASSETS
NON-CURRENT ASSETS
Property, plant and equipment	11.1		2,544		2,164
Intangible assets	11.2		96		138
Right-of-use assets	19.1.1		21		9
Deferred tax asset	11.3		-		36
Investments in associates and joint ventures	5.3.2		672		902
Financial assets at amortized cost	12.1		-		102
Financial assets at fair value through profit and loss	12.2		35		27
Other assets			-		1
Trade and other receivables	12.3		18		20
Total non-current assets			3,386		3,399
CURRENT ASSETS
Inventories	11.4		205		173
Financial assets at amortized cost	12.1		105		8
Financial assets at fair value through profit and loss	12.2		559		586
Trade and other receivables	12.3		296		470
Cash and cash equivalents	12.4		171		106
Total current assets			1,336		1,343
Total assets			4,722		4,742

CONSOLIDATED STATEMENT OF FINANCIAL POSITION (Continuation)

As of December 31, 2023 and 2022

(In millions of US$ - unless otherwise stated)

	Note		12.31.2023		12.31.2022
SHAREHOLDERS´ EQUITY
Share capital			36		36
Share capital adjustment			191		191
Share premium			516		516
Treasury shares adjustment			1		1
Treasury shares cost			(7)		(23)
Legal reserve			45		45
Voluntary reserve			1,433		968
Other reserves			(15)		(15)
Other comprehensive (loss) income			(19)		81
Retained earnings			223		477
Equity attributable to owners of the company			2,404		2,277
Non-controlling interest			9		7
Total equity			2,413		2,284
LIABILITIES
NON-CURRENT LIABILITIES
Provisions	11.5		150		147
Income tax and minimum notional income tax provision	11.6		55		179
Deferred tax liability	11.3		297		112
Defined benefit plans	11.8		16		28
Borrowings	12.5		1,224		1,340
Trade and other payables	12.6		46		21
Total non-current liabilities			1,788		1,827
CURRENT LIABILITIES
Provisions	11.5		6		4
Income tax liability	11.6		17		5
Tax liabilities	11.7		14		28
Defined benefit plans	11.8		3		6
Salaries and social security payable	11.9		19		32
Derivative financial instruments			-		2
Borrowings	12.5		224		273
Trade and other payables	12.6		238		281
Total current liabilities			521		631
Total liabilities			2,309		2,458
Total liabilities and equity			4,722		4,742

The accompanying notes are an integral part of these Consolidated Financial Statements.

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the years ended December 31, 2023, 2022 and 2021

(In millions of US$ - unless otherwise stated)

	Attributable to owners
	Equity holders of the company		Retained earnings
	Share capital		Share capital adjustment		Share premium		Treasury shares		Treasury shares adjustment		Treasury shares cost		Legal reserve		Voluntary reserve		Other reserves		Other comprehensive income / (loss)		Retained earnings (Accumulated losses)		Subtotal		Non-controlling interest		Total equity
Balance as of December 31, 2020	38		201		516		-		1		(6)		61		1,057		(18)		(50)		(372)		1,428		341		1,769
Legal and voluntary reserve constitution	-		-		-		-		-		-		-		(372)		-		-		372		-		-		-
Capital reduction	-		-		-		(2)		(10)		38		-		(26)		-		-		-		-		-		-
Treasury shares acquisition	(2)		(10)		-		2		10		(39)		-		-		-		-		-		(39)		-		(39)
Stock compensation plans	-		-		-		-		-		-		-		-		3		-		-		3		-		3
Sale of subsidiary	-		-		-		-		-		-		-		-		-		-		-		-		(334)		(334)
Profit (Loss) of the year	-		-		-		-		-		-		-		-		-		-		273		273		(35)		238
Other comprehensive income of the year	-		-		-		-		-		-		-		-		-		98		22		120		34		154
Balance as of December 31, 2021	36		191		516		-		1		(7)		61		659		(15)		48		295		1,785		6		1,791
Legal and voluntary reserve constitution	-		-		-		-		-		-		(16)		311		-		-		(295)		-		-		-
Capital reduction	-		-		-		-		-		2		-		(2)		-		-		-		-		-		-
Treasury shares acquisition	-		-		-		-		-		(18)		-		-		-		-		-		(18)		-		(18)
Profit of the year	-		-		-		-		-		-		-		-		-		-		456		456		1		457
Other comprehensive income of the year	-		-		-		-		-		-		-		-		-		33		21		54		-		54
Balance as of December 31, 2022	36		191		516		-		1		(23)		45		968		(15)		81		477		2,277		7		2,284

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY (Continuation)

For the years ended December 31, 2023, 2022 and 2021

(In millions of US$ - unless otherwise stated)

	Attributable to owners
	Equity holders of the company		Retained earnings
	Share capital		Share capital adjustment		Share premium		Treasury shares adjustment		Treasury shares cost		Legal reserve		Voluntary reserve		Other reserves		Other comprehensive income		Retained earnings		Subtotal		Non-controlling interest		Total equity
Balance as of December 31, 2022	36		191		516		1		(23)		45		968		(15)		81		477		2,277		7		2,284
Legal and voluntary reserve constitution	-		-		-		-		-		-		478		-		-		(478)		-		-		-
Capital reduction	-		-		-		-		16		-		(13)		-		-		-		3		-		3
Dividens ditribution	-		-		-		-		-		-		-		-		-		-		-		(1)		(1)
Profit for the year	-		-		-		-		-		-		-		-		-		302		302		3		305
Other comprehensive loss for the year	-		-		-		-		-		-		-		-		(100)		(78)		(178)		-		(178)
Balance as of December 31, 2023	36		191		516		1		(7)		45		1,433		(15)		(19)		223		2,404		9		2,413

The accompanying notes are an integral part of these Consolidated Financial Statements.

CONSOLIDATED STATEMENT OF CASH FLOWS

For the years ended December 31, 2023, 2022 and 2021

(In millions of US$ - unless otherwise stated)

	Note		12.31.2023		12.31.2022		12.31.2021
Cash flows from operating activities:
Profit of the year from continuing operations			305		457		313
Adjustments to reconcile net profit to cash flows from operating activities	14.1		406		302		362
Changes in operating assets and liabilities	14.2		(136)		(140)		(62)
Net cash generated by operating activities from discontinued operations	5.2.1		-		-		116
Net cash generated by operating activities			575		619		729
Cash flows from investing activities
Payment for property, plant and equipment acquisitions			(758)		(416)		(206)
Payment for intangible assets acquisitions			-		(31)		(4)
Collections for sales (Payment for) public securities and shares acquisitions, net			130		(102)		(234)
Recovery (Subscription) of mutual funds, net			96		(1)		52
Payment for the acquisition of companies			(1)		(111)		(17)
Collection for equity interests in companies sales			72		44		51
Collections for property, plant and equipment sales			1		-		1
Collections for intangible assets sales			20		21		5
Dividends received			-		10		18
(Payment) Collection of loans			(6)		11		26
Net cash used in investing activities from discontinued operations	5.2.1		-		-		(166)
Net cash used in investing activities			(446)		(575)		(474)
Cash flows from financing activities
Proceeds from borrowings	12.5		424		308		188
Payment of borrowings	12.5		(191)		(143)		(336)
Payment of borrowings interests	12.5		(280)		(162)		(140)
Payment for treasury shares acquisition			-		(18)		(39)
Repurchase of corporate bonds	12.5		(6)		(28)		(3)
Payments of leases			(3)		(3)		(5)
Payments of dividends			(1)		-		-
Net cash used in financing activities from discontinued operations	5.2.1		-		-		(7)
Net cash used in financing activities			(57)		(46)		(342)
Increase (Decrease) in cash and cash equivalents			72		(2)		(87)
Cash and cash equivalents at the beginning of the year	12.4		106		110		141
Cash and cash equivalents at the beginning of the year reclasified to assets classified as held for sale	5.2.1		-		-		52
Exchange difference generated by cash and cash equivalents			(7)		(2)		4
Increase (Decrease) in cash and cash equivalents			72		(2)		(87)
Cash and cash equivalents at the end of the year	12.4		171		106		110

The accompanying notes are an integral part of these Consolidated Financial Statements.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2023, 2022 and 2021

(In millions of US$ - unless otherwise stated)

NOTE 1: GENERAL INFORMATION

1.1 General information of the Company

The Company is a fully integrated power company in Argentina, which participates in the electric energy, oil and gas value chains.

In the generation segment, the Company, directly and through its subsidiaries and joint ventures, has a 5,332 MW installed capacity as of December 31, 2023, which represents approximately 12% of Argentina's installed capacity, and being one of the four largest independent generators in the country. Additionally, the Company is currently undergoing a process to expand its installed capacity by an additional 140 MW.

In the oil and gas segment, the Company develops an important activity in gas and oil exploration and production, with operations in 12 production areas and 5 exploratory areas reaching a production level of 10.3 million m3/day of natural gas and 4.8 thousand boe/day of oil in Argentina, as of December 31, 2023. Its main natural gas production blocks are located in the Provinces of Neuquén and Río Negro.

In the petrochemicals segment, operations are located in Argentina, where the Company operates 2 high-complexity plants producing styrene, synthetic rubber and polystyrene, with a domestic market share ranging between 91% and 100%.

Finally, through the holding and others segment, the Company participates in the electricity transmission and oil and gas transportation businesses. In the transmission business, the Company jointly controls Citelec, which has a controlling interest in Transener, a company engaged in the operation and maintenance of a 22,391 km high-voltage electricity transmission network in Argentina with an 86% share in the Argentine electricity transmission market. In the gas transportation business, the Company jointly controls CIESA, which has a controlling interest in TGS, a company holding a concession for the transportation of natural gas with 9,248 km of gas pipelines in the center, west and south of Argentina, and which is also engaged in the processing and sale of natural gas liquids through the Cerri Complex, located in Bahía Blanca, in the Province of Buenos Aires, in addition to shale gas transportation and conditioning at Vaca Muerta. Besides, the Company owns a 34.08% indirect interest in OCP (see Note 5.3.4), licensee company of an oil pipeline in Ecuador that has a transportation capacity of 450 thousand barrels/day. Additionally, the segment includes advisory services provided to related companies.

NOTE 1: (Continuation)

1.2 Economic context

The Company operates in an economic context which main variables are experiencing volatility as a result of political and economic events both in the domestic and international spheres.

At the local level, the Argentine economy was affected during the first half of 2023, and for the third consecutive year, by the La Niña weather phenomenon, which extended the drought period, affecting agricultural production and generating a significant adverse impact on exports and fiscal revenues. As a result, at the end of August 2023, the International Monetary Fund granted the relaxation of certain fiscal and monetary targets for the country and access to approximately US$7,500 million, together with a commitment to implement a new policy package.

Finally, on December 10, 2023, a new government took office in Argentina that proposes to move forward with the deregulation of the economy and a series of structural reforms aimed at freeing up restrictions to invest and operate in the country. Among its first measures, on December 21, 2023, PEN Executive Order No. 70/23, "Bases for reconstructing the Argentine economy", was issued, whereby it declared a public emergency in economic, financial, fiscal, administrative, social security, tariff, health and social matters until December 31, 2025, and set the basis for economic deregulation and State reform, and provided for extensive modifications to different legal systems. The PEN Executive Order seeks to amend 300 laws, including reforms to the labor market, the customs code and the status of public companies, among others. Although the PEN Executive Order must be discussed and ratified by at least one of the Chambers of the National Congress, its provisions are partially effective as from December 29, 2023, considering a series of judicial actions that have granted the suspension of certain modifications.

Regarding the energy industry, in August 2023, transportation operations of the new Tratayén - Salliqueló section of the Presidente Néstor Kirchner gas pipeline began, with the expectation of generating fiscal and productive benefits, better employment, production and energy supply indicators in the country, and other benefits such as an increase in royalties for the producing provinces and foreign currency savings resulting from a decrease in imports. The above is complemented by the Reversion of the Northern Gas Pipeline, which is expected to transport gas from Vaca Muerta to seven provinces in northern Argentina that are currently supplied with imports from Bolivia. Additionally, in a second instance, these works would allow moving forward with exports to the north of Chile and Brazil.

NOTE 1: (Continuation)

Besides, on December 18, 2023, PEN Executive Order No. 55/23 was issued declaring the emergency in the national energy sector comprising electricity generation, transmission and distribution and natural gas transportation and distribution, effective until December 31, 2024.

In general terms, the severe drought has deteriorated economic conditions and deepened pre-existing macroeconomic imbalances. The Argentine economy recorded a 1.6% accumulated decrease in the Gross Domestic Product as of the third quarter of 2023, a 211.4% cumulative inflation considering the CPI and a 356.3% depreciation of the peso against the U.S. dollar, according to the BNA exchange rate, for fiscal year 2023. In turn, a 6.4% cumulative growth of the Gross Domestic Product as of the third quarter of 2022, a 94.8% increase in the CPI and a 72.5% depreciation of the peso against the U.S. dollar were recorded for fiscal year 2022.

The context of volatility and uncertainty continues as of the date of issuance of these Consolidated Financial Statements. The reforms proposed by the new government have begun their legislative discussion process. It is not possible to currently foresee their evolution or any new measures that may be announced.

The Company's Management permanently monitors the evolution of the variables affecting its business to define its course of action and identify potential impacts on its assets and financial position.

The Company's financial statements should be read in the light of these circumstances.

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:

NOTE 2: (Continuation)

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<>	Resolution No. 869/23
HIDISA	EL TIGRE	HR	Renewable ≤ 50	Resolution No. 869/23
HIDISA	LOS REYUNOS	HB	HB - Media 120<>	Resolution No. 869/23
HINISA	NIHUIL I - II - III	HI	HI - Small 50<>	Resolution No. 869/23
HPPL	PPLEHI	HI	HI - Media 120<>	Resolution No. 869/23
PEPE II	PAMEEO	Wind	53 MW	MATER Res. No. 281/17
PEPE III	BAHIEO	Wind	53 MW	MATER Res. No. 281/17
PEPE IV	Ampliación BAHIEO	Wind	81 MW	MATER Res. No. 281/17
PE Arauco	AR21EO	Wind	99,75 MW	Renovar
(1) Surplus power capacity and energy are remunerated in the spot market.
In construction:
Generator	Tecnology	Capacity	Applicable regime
PEPE VI	Wind	140 MW	MATER Res. No. 281/17

NOTE 2: (Continuation)

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.

NOTE 2: (Continuation)

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.

NOTE 2: (Continuation)

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.

NOTE 2: (Continuation)

Pursuant to this resolution, the Company, through its CTLL, CTIW and CTPP power plants, has effective agreements with CAMMESA for the sale of energy and power capacity for a total 305 MW.

2.1.3.3 SE Resolution No. 287/17

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

Pursuant to this regulation, the Company, through its CTGEBA thermal power plant, has entered into a wholesale power purchase agreement with CAMMESA for the sale of energy and power capacity for a total 400 MW, for a term of 15 years.

2.1.3.4 Renovar Programs

In order to meet the objectives, set by Law No. 26,190 and Law No. 27,191 promoting the use of renewable sources of energy, the MEyM called for open rounds for the hiring of electric power from renewable sources (Renovar Programs, Rounds 1, 1.5 and 2) within the WEM. These calls aimed to assign power capacity contracts from different technologies (wind energy, solar energy, biomass, biogas and small hydraulic developments with a power capacity of up to 50 MW).

For the awarded projects, renewable electric power supply agreements were executed for the sale of an annual committed electric power block for a term of 20 years.

Additionally, several measures were established to promote the construction of projects for the generation of energy from renewable sources, including tax benefits (advance VAT reimbursement, equipment's accelerated depreciation in the income tax, import duty exemptions, etc.) and the creation of a Fund for the Development of Renewable Energies ("FODER") destined, among other objectives, to the granting of loans and capital contributions for the financing of such projects.

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

2.1.3.5 Penalty system under MATER and Renovar contracts

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

NOTE 2: (Continuation)

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.

NOTE 2: (Continuation)

2.1.4 Remuneration at the Spot market

On May 19, 2021, SE Resolution No. 440/21 provided for a 29% increase in the values in pesos of the remuneration items based on technology and scale and the additional remuneration for the power capacity generated in the hours of maximum thermal demand of the month established in SE Resolution No. 31/20.

In November 2021, SE Resolution No. 1,037/21, instrumented through Note NO-2021-108163338-APN-SE#ME, provided for an additional transitional remuneration for generated energy and suspended the application of the utilization factor for economic transactions comprised between September 1, 2021 and February 28, 2022.

On April 21, 2022, SE Resolution No. 238/22 was published in the BO. This resolution provided a 30% increase in spot generation remuneration values from the February 2022 economic transaction, and an additional 10% increase from the June 2022 economic transaction. It also abrogated the application of the utilization factor and the additional transitional remuneration set by SE Resolution No. 1,037/21.

On December 14, 2022, through SE Resolution No. 826/22, the spot remuneration values were modified considering the following increases: i) 20% from the September 2022 economic transaction; ii) 10% from the December 2022 economic transaction; iii) 25% from the February 2023 economic transaction; and iv) 28% from the August 2023 economic transaction.

Additionally, SE Resolution No. 826/22 replaced the remuneration scheme at hours of maximum thermal demand with a differentiated remuneration scheme at peak hours from the November 2022 economic transaction.

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

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

2.1.4.1 Remuneration for Available Power Capacity

2.1.4.1.1 Thermal Power Generators

A minimum remuneration for power capacity based on technology and scale was established, and generating, co-generating and self-generating agents owning conventional thermal power plants were allowed to offer guaranteed availability commitments for the energy and power capacity generated by their units and not committed under sales contracts with large users within the MAT and supply agreements with CAMMESA.

Availability commitments are tendered for quarterly periods: a) summer (December through February); b) winter (June through August) and c) 'other,' which comprises two quarters (March through May, and September through November), the thermal generators' remuneration for committed power capacity being proportional to their compliance.

NOTE 2: (Continuation)

The minimum remuneration for generators with no availability commitments includes the following scales and prices:

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

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

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

In the case of thermal power plants with a power capacity equal to or lower than 42 MW in total, a differential remuneration was applied until its elimination on August 2022.

In the same way, a coefficient derived from the average utilization factor over the unit's last twelve months was applied to the power capacity remuneration: with a minimum 70% of the utilization factor, 100% of the power capacity payment was collected; if the utilization is between 30% and 70%, the power capacity payment ranged from 70% to 100%; and if the utilization factor was lower than 30%, 70% and 60% of the power capacity payment was collected until January 2020 and August 2021. Subsequently, the application of this factor was suspended in 2021 and finally abrogated from February 2022.

2.1.4.1.2 Hydroelectric Generators

Power capacity availability is determined independently of the reservoir level, the contributions made, or the expenses incurred. Furthermore, in the case of pumping hydroelectric power plants, the operation as turbine and pump is considered to calculate availability.

The base remuneration includes the following scales and prices:

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

The payment for power capacity is determined by the actual capacity, hours of unavailability due to programmed and/or agreed maintenance are not computed for the calculation of the remuneration. However, to consider the incidence of programmed maintenance works in power plants, SME Note No. 46631495/19 provided for the application of a 1.05 factor over the power capacity payment.

NOTE 2: (Continuation)

In the case of hydroelectric power plants maintaining control structures on river courses and not having an associated power plant, a 1.20 factor is applied to the plant at the headwaters.

2.1.4.2 Remuneration for generated and operated energy

In the case of thermal power generators, a remuneration was set for generated energy, depending on the type of fuel used, and for operated energy, as shown below:

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

It is worth highlighting that if the thermal generation unit operates outside its optimal dispatch, the remuneration for generated energy will be recognised at 60% of the installed net capacity, irrespective of the energy delivered by the unit.

In the case of hydroelectric plants, the following prices were established for generated and operated energy, irrespective of scale:

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

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

In the case of pumping hydroelectric power plants, both the generated energy and that used for pumping are considered. Besides, if it works as a synchronous condenser, 77 $/MVAr, 145 $/MVAr and 367 $/MVAr are recognised under SE Resolution No. 440/21, No. 238/22, No. 826/22 and 869/23, respectively, for the megavolt-amperes exchanged with the grid when required, in addition to the prices for operated energy.

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

Remuneration	SE No. 440/21 ($ / MWh)	SE No. 826/22 ($ / MWh)	SE No. 869/23 ($ / MWh)
Generated energy	2,167	3,719	10,304

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

NOTE 2: (Continuation)

2.1.4.3 Additional remuneration

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

Thermal units:

Period	SE No. 440/21	SE No. 238/22
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)
Summe - Winter	54,180	27,090	77,478	38,739
Fall - Spring	9,030	-	12,913	-

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

2.1.4.4 Remuneration for combined cycles

SE Resolution No. 59/23 dated February 7, 2023 established a system combined cycles' owners could opt-in by executing an availability and efficiency optimization agreement with CAMMESA. The agreement contemplates an availability commitment of 85% of the net power capacity for a maximum term of 5 years, and sets a US$ 2,000/MW-month remuneration for the power capacity made available and the dollarization of the energy price based on the fuel used (US$ 3.5/MWh for natural gas and US$ 6.1/MWh for fuel oil and gas oil). Besides, it provides for a 35% and 15% reduction in the remuneration collectible for guaranteed power capacity for generators with availability commitments in the spot market for the summer-winter and autumn-spring periods, respectively.

NOTE 2: (Continuation)

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.

NOTE 2: (Continuation)

(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:

NOTE 2: (Continuation)

(i)	Sets the terms for exploration permits:

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

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

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

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

-	Conventional exploitation concession: 25 years;

-	Unconventional exploitation concession: 35 years; and

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

(iii)

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

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

(v)

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

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

(vii)

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

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

NOTE 2: (Continuation)

2.2.2 Hydrocarbon exploration and exploitation levy

Law No. 27,007 set the levy values per km2 or fraction for exploitation and exploration permits, payable annually and in advance by the permit holder. On September 26, 2019, the Province of Neuquén, pursuant to Provincial Executive Order No. 2,032/19, published new levy values per km2 or fraction effective for this province as from 2020.

From 2021, PEN Executive Order No. 771/20 set a maximum levy in pesos equivalent to a certain volume of oil at the average price for the semester before settlement, at BNA's exchange rate effective on the last business day before payment. This scheme is applicable nationwide (including the Province of Neuquén, which acceded to it under Provincial Executive Order No. 1,656/20). Exploitation permits amount to 8.28 barrels and exploration permits to 0.46 barrels in the first period, 1.84 barrels in the second period of the basic term, and 32.22 barrels in the extension period.

2.2.3 Currency access for incremental oil and natural gas production systems and regional and national supplier's employment, labor and development promotion system

On May 28, 2022, PEN Executive Order No. 277/22 was published, which established currency access systems for the incremental production of oil ("RADPIP") and natural gas ("RADPIGN"), as well as the regional and national supplier's employment, labor and development promotion system ("RPEPNIH"). This executive order, later regulated by PEN Executive Order No. 484/22 dated August 12, 2022, mainly provided for eased access to the MLC for beneficiaries increasing their gas injection levels and/or oil production.

Beneficiaries must meet the following requirements to access the RADPIP and the RADPIGN: (i) be registered with the SE's oil companies registry; (ii) accede to the system; (iii) attain an incremental oil production or natural gas incremental injection levels; (iv) comply with the RPEPNIH; and (v) be an awardee and fulfill the obligations provided under natural gas production promotion or stimulus programs (exclusively for the RADPIGN).

Beneficiaries under these systems may access the MLC to make principal and interest payments of commercial or financial liabilities abroad, including liabilities with non-resident affiliates, and to pay earnings and dividends for closed and audited balance sheets and/or the repatriation of direct investments by non-residents. This benefit may be transmitted to direct suppliers. Moreover, access to the MLC under this system will not be subject to BCRA's prior authorization requirement in case exchange regulations so require.

Currency access benefits for acceding the RADPIP and/or RADPIGN will be taken into consideration and timely discounted.

Regarding the RPEPNIH, supplier development plans guaranteeing regional and national integration will be controlled. Moreover, a hiring scheme is contemplated granting preferences to regional and national goods and/or services suppliers.

On January 16, 2023, SE Resolution No. 13/23 was published in the BO, which regulated the opt-in system and the procedure to obtain the currency access benefit created by PEN Executive Order No. 277/22.

NOTE 2: (Continuation)

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

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

2.2.4 Gas Market

2.2.4.1 Natural Gas Production Promotion or Stimulus Programs

2.2.4.1.1 Argentine Natural Gas Production Promotion Plan ("GasAr Plan")

On November 16, 2020, Executive Order No. 892/20 was published in the BO, which approved the GasAr Plan to foster the development of the Argentine gas industry based on a bidding mechanism, and instructed the SE to instrument such plan and to set the applicable complementary and clarifying rules.

On November 23, 2020, the SE, through Resolution No. 317/20, launched the "National Public Call for Tenders for the Argentine Natural Gas Production Promotion Plan - 2020-2024 supply and demand scheme" for the award of a volume of 70 million m3 of natural gas per calendar year (CAMMESA plus distributors), which may be modified by the SE to guarantee an optimal domestic supply.

The contract samples stipulated a Deliver or Pay ("DOP") obligation of 100% per day for producers and a Take or Pay ("TOP") obligation of 75% per month for CAMMESA and per quarter for distributors. Regarding the payment of contracts with distributors, the Federal Government will bear the monthly difference between the price tendered and that resulting from the tariff schemes through a subsidy payable directly to producers. Under Law No. 27,591, payment of this subsidy is secured by Tax Credit Certificates, which were regulated by SE Resolution No. 125/21 and AFIP General Resolution No. 4,939/21.

Additionally, to access the GasAr Plan producers submitted a plan of investments necessary to maintain the committed production and a national added-value commitment providing for the development of direct local, regional and national suppliers.

On December 15, 2020, Resolution No. 391/20 was published in the BO, awarding the natural gas volumes tendered under GasAr Plan, Round 1. In this sense, out of a total natural gas base volume of 67.42 million m3/day to be purchased, in terms of tendered volume, the Company ranked third in the Neuquina Basin, with an awarded base volume of 4.9 million m3/day at an annual average price of US$ 3.60/MBTU for a term of four years effective as from January 1, 2021.

Additionally, the Company has been one of the three producers tendering an additional volume for the winter period, with the award of 1 million m3/day at US$ 4.68/MBTU, a volume deemed indispensable to accompany the high seasonality of the Argentine demand, reducing gas imports, the consumption of alternative fuels, and the use of foreign-currency reserves.

NOTE 2: (Continuation)

On March 9, 2021 Resolution No. 169/21 was published in the BO, which awarded natural gas volumes offered under the GasAr Plan, Round 2 Tender. In this sense, the Company was awarded a volume of 0.70 million m3/day, 0.90 million m3/day and 1 million m3/day for the months of June, July and August-September 2021, respectively, and 0.86 million m3/day to meet the winter peak demand for the years 2022 through 2024, at a price of US$ 4.68/MBTU.

Under Resolution No. 984/21 dated October 19, 2021, the SE called for Round 3 under GasAr Plan for 2022 through 2024 inclusive, with injection starting in May 2022. The resolution determined that the cap price for tenders is the maximum price tendered under Round 1. The Company took part in this call, tendering 2 million m3/day for the Neuquina basin at a price of US$ 3.347/MBTU; on November 11, 2021, the SE issued Resolution No. 1,091/21, awarding the tendered volumes and prices.

2.2.4.1.2 2023-2028 Plan to Reinsure and Encourage Federal Hydrocarbon Production, Domestic Self-Supply, Exports, Imports Substitution, and the Expansion of the Transportation System for all the Country's Hydrocarbon Basins ("Reinsurance Plan")

On November 3, 2022, Executive Order No. 730/22 was published in the BO, which amended the GasAr Plan's scheme approved by Executive Order No. 892/20.

The Reinsurance Plan establishes a new term for the system until December 31, 2028, with the following main objectives: (i) consolidating a new 70 MMm3/d flat block (volumes awarded under GasAr Plan's Round 1 and 3), excluding winter peaks; and (ii) developing the demand for the incremental volumes to be evacuated using the new transportation capacity following the construction of the Néstor Kirchner Gas Pipeline (TransportAr Program, SE Resolution No. 67/22).

Consequently, on November 14, 2022, SE Resolution No. 770/22 was published in the BO, calling for Tender Rounds 4 for the Neuquina Basin, and 5, for the Del Golfo and Austral Basins.

For the Neuquina Basin, the following calls were made:

(i) Round 4.1: for the extension of the commitments undertaken under Rounds 1 and 3 of the GasAr Plan for 4 additional years, from January 1, 2025 to December 31, 2028, for the same volumes, and with prices equal to or lower than the timely awarded price; and

(ii) Round 4.2: for the award of the following incremental volumes:

(a)	Flat Gas: 11 MMm3/day from July 1, 2023 to December 31, 2028, and 3 MMm3/day from January 1, 2024 to December 31, 2028, with prices not exceeding US$ 4 MBTU; and

(b)	Peak Gas: 7 MMm3/day from May 1 to September 30, for each of the 2024-2028 and 2025-2028 periods, with prices equal to or lower than US$ 6.9 MBTU and an applicable 1.3 adjustment factor.

NOTE 2: (Continuation)

The Company participated in Round 4.1, seeking to extend commitments under GasAr Plan's Rounds 1 and 3 until December 2028 and keeping the originally tendered prices of US$ 3.6 MBTU and US$ 3.347 MBTU, respectively. Moreover, it submitted the following tenders under Round 4.2: (i) Flat Gas: 4.8 million m3/day at a price of US$ 3.485 MBTU from July 1, 2023 to December 31, 2028; (ii) Peak Gas: 3 million m3/day at a price of US$ 5.190 MBTU for the 2024-2028 period and 1.9 million m3/day at US$ 4.770 MBTU for the 2025-2028 period.

On December 22, 2022, through SE Resolution No. 860/22, the Company was awarded the extension of the commitments for Round 4.1 and a 4.8 million m3/day demand associated with flat gas under Round 4.2.

The awards granted to the Company and the contracts executed represent a production commitment of 15.7 million m3/day for winter periods and 13.8 million m3/day for summer periods in 2023-2024. Compared to 2022, this commitment represents a 44% increase in winter production, the period with the largest gas supply needs in the country. As from 2025, the commitment under the Reinsurance Plan will amount to 13.8 million m3/day.

Based on the gas demand curve projected by the SE, the Company will enter into new contracts with CAMMESA, ENARSA and distributors.

2.2.4.1.3 Plan GasAr's Round 5.2 - Aguaragüe Joint Operation

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

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

2.2.4.2 Natural gas for the residential segment and CNG

On May 27, 2022, SE Resolution No. 403/22 provided for an update of new natural gas PIST prices under existing contracts executed within the framework of GasAr Plan's promotion scheme, reducing the subsidy payable by the Federal Government from June 1, 2022.

Additionally, in the months of February, June and August 2022, public hearings were held to analyze the Plan Gas.Ar portion of the natural gas PIST price to be borne by the Federal Government. It is worth highlighting that SE Resolution No. 610/22 determined a gradual increase in the PIST price distributors will pay for unsubsidized residential consumptions, keeping the subsidized price for the remaining users.

On January 10, 2023, SE Resolution No. 6/23 was published, establishing updates of natural gas PIST prices for contracts executed under the GasAr Plan and the Reinsurance Plan based on the different types of users.

NOTE 2: (Continuation)

2.2.4.3 Acquisition of Natural Gas for Generation

From December 30, 2019, CAMMESA's centralization scheme for the supply of fuels for generation was restored (except for generators with Energy Plus and SE Res. No. 287/17 contracts). Since then, CAMMESA has launched successive calls for tenders to cover its monthly consumption. Moreover, from 2021, most gas supplies to CAMMESA are channeled through GasAr Plan, for the volumes committed under this program over an initial term of 4 years.

In addition to GasAr Plan, since mid-July 2021 CAMMESA launched biweekly calls for tenders by GasAr Plan awardees that may offer surplus volumes, with a maximum price equivalent to that awarded in the plan's Round 1.

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

Additionally, in 2023, 25 million m3/day were awarded in complementary calls at US$2.6/MBTU (of which 15 million m3/day correspond to the Neuquina Basin).

2.2.4.4 Natural Gas Exports

On April 27, 2021, SE Resolution No. 360/21 regulated the new procedure for the authorization of natural gas exports. This resolution contemplates exports on a firm and preferential basis for GasAr Plan's awardees, and sets a minimum sale price equivalent to the summer price awarded in Round 1. In this manner, the Company, as an awardee under GasAr Plan, may make firm exports during the summer period, extendable to the winter period when there is an oversupply in a specific basin and with the prior approval of the applicable authority.

In May and December 2021, Pampa was granted permits to export gas to Chile on a firm basis for a maximum volume of 1.5 million m3/day and 1.22 million m3/day for the October 2021 - April 2022 and January - April 2022 periods, respectively. Besides, between September and December 2021, new interruptible permits to Chile, Brazil, and Uruguay were added, with expirations between November 2022 and December 2024.

Under GasAr Plan, in August 2022 the Company was cleared to export gas to Chile on a firm basis for a maximum volume of 1,492 MMm3/d for the October 2022 - April 2023 period.

On November 17, 2022, SE Resolution No. 774/22, which supersedes SE Resolution No. 360/21, was published in the BO. This resolution establishes a new proceeding delimiting four export areas: the Neuquina Basin and the Austral Basin with summer quotas (October 2023-April 2024 period) of 9 MMm3/day and 2 MMm3/day, respectively, and the Noroeste Basin and other areas with no quota definition.

The distribution of firm summer quotas among producers is made considering (i) the share of the producer's volume in the basin's total volume, and (ii) the highest discount in the weighted-average price discount per volume against the basin's incremental volume.

The minimum reference price is set at the higher of the Brent quotation percentage determined by the SE and the average price awarded, adjusted by the seasonal index, with the authorization to withdraw volumes from the contracts executed under GasAr Plan and/or the Reinsurance Plan with CAMMESA and/or ENARSA.

NOTE 2: (Continuation)

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

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

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

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

It is worth highlighting that a natural gas export duty has been in effect since May 2020. PEN Executive Order No. 488/20, issued on May 19, 2020, established an export duty exemption as long as the international Brent price was equal to or below US$45/bbl. The rate would rise gradually in line with the international reference price until reaching 8%, the cap to be recognized when Brent equals or exceeds US$60/bbl. Since February 2021, the rate has remained at 8%.

2.2.4.5 "TransportAr National Production" Pipelines System Program

On February 9, 2022, SE Resolution No. 67/22 was published in the BO declaring the construction of "President Néstor Kirchner Pipeline" of national public interest. This pipeline will transport natural gas through the Province of Neuquén, the Province of Buenos Aires, and the Province of Santa Fe.

Moreover, it created the TransportAr Production Gas Pipelines System Program to execute the works necessary to expand the system's transportation capacity including a list of pipeline works to be executed by ENARSA or through third parties to promote development, production growth, and natural gas self-supply, among other objectives.

On August 10, 2022, Argentine authorities signed contracts for the Stage 1 Néstor Kirchner Gas Pipeline construction, (Tratayén - Salliqueló).

Later, PEN Executive Order No. 76/22, published on February 14, 2022, granted ENARSA a 35-year transportation concession of President Néstor Kirchner pipeline under Law No. 17,319 and the power to contract, plan, execute and call for tenders for the construction of the infrastructure works under the Program. ENARSA may enter into transportation capacity freely-negotiated agreements with producers and/or carriers to construct or expand all or part of the pipeline. This transportation capacity will not be covered by tariffs approved by ENARGAS, which will apply to the remaining transportation capacity not committed under these agreements. This executive order grants YPF priority to hire the capacity that can be freely negotiated by ENARSA. Moreover, ENARSA may fully or partially assign ownership of its concession to YPF.

NOTE 2: (Continuation)

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

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

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

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

2.2.5 Oil market

2.2.5.1 Crude oil price

As of this date, there is no reference price for the sale of crude oil in the domestic market. However, considering pump prices for fuels, local refining companies are validating prices below the export parity.

Just as with natural gas exports, a crude oil export duty has been in effect since May 2020. PEN Executive Order No. 488/20, issued on May 19, 2020, provided for an export duty exemption as long as the international Brent price was equal to or below US$ 45/bbl, rising gradually as the international reference price increased until reaching 8%, the cap to be recognised when the reference price equals or exceeds US$ 60/bbl. Since February 2021, the rate has remained at 8%.

2.2.5.2 Oil transportation

In fiscal year 2022, Oldelval, as holder of the national liquid hydrocarbons transportation concession, launched a call for tenders to award and hire the firm transportation service for the Allen - Puerto Rosales oil pipeline tranche for a capacity of up to 50,000 m3/day.

This volume has been fully awarded, and the necessary execution contracts have been entered into, effective until the termination of the transportation concession term in 2037. Pampa was awarded 1,002 m3/day.

Under Oldelval's call for tenders, the company Oiltanking Ebytem launched a call to increase the oil dispatch capacity for up to 50,000 m3/day and the storage capacity for up to 300,000 m3. These expansions will be allocated exclusively to oil exports. Pampa was awarded a 1,002 m3/day dispatch capacity and oil storage capacity for 6,008 m3.

NOTE 2: (Continuation)

2.3 Gas Transportation

2.3.1 TGS's Tariff situation

On March 30, 2017, TGS executed the 2017 Integral Agreement which was ratified on March 27, 2018, through PEN Executive Order No. 250/18. This executive order represents the conclusion of the RTI process and terminates all transitional agreements celebrated by TGS.

The 2017 Integral Agreement set the guidelines for the provision of the natural gas transportation service until the end of the license, among these guidelines approved: (i) a tariff increase was granted in installments for TGS as from April 1, 2017; (ii) a Five-Year Investment Plan to be executed by TGS between April 2017 and March, 2022; and (iii) a non-automatic six-month adjustment mechanism for the natural gas transportation tariff and the investment commitments considering IPIM published by INDEC subject to ENARGAS' approval.

In the public hearing held on September 4, 2018, in which TGS requested, based on the variation of the IPIM recorded for the period February - August 2018, a tariff increase of approximately 30%. Considering the hearing, on September 27, 2018, ENARGAS issued Resolution No. 265/18 which determined a 19.7% tariff increase effective as of October 1, 2018.

This increase was determined by ENARGAS based on the simple average of the IPIM, the construction cost index for the period February and August 2018 and the Salary Variation Index between December 2017 and June 2018. ENARGAS supported the determination of the aforementioned tariff increase in the provisions of Resolution No. 4,362/17, which, among other issues, provided that under certain circumstances and macroeconomic conditions, such as the significant devaluation occurred after April 2018, ENARGAS may use other indexes than the IPIM to determine the tariff increase. TGS notified ENARGAS of its disagreement with respect to the methodology for calculating the semi-annual adjustment.

On March 29, 2019, ENARGAS issued Resolution No. 192/19 approved, effective as from April 1, 2019, a 26% increase in tariff schemes applicable to the natural gas transportation utility by TGS current as of March 31, 2019. In accordance with current regulations, ENARGAS considered the evolution of the IPIM update index between the months of August 2018 and February 2019 to define six-monthly adjustments to TGS' tariffs.

As regards the semi-annual tariff update which should have become effective as from October 1, 2019, on September 3, 2019, the SE issued Resolution No. 521/19, later amended by Resolution No. 751/19, postponed its application until February 1, 2020. This deferral resulted in the revision and adjustment of the Five-Year Investment Plan execution, in the same proportion as the foregone income for TGS.

On December 16, 2020, PEN Executive Order No. 1,020/20 was passed within the framework of the Solidarity Law, later extended by PEN Executive Order No. 815/22, launching the renegotiation of the RTI concluded in 2018 while suspending renegotiation agreements in force until December 16, 2023 and providing for the administrative intervention of the ENARGAS.

NOTE 2: (Continuation)

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

Additionally, TGS denied and dismissed the arguments raised in the public hearing, which considered that the current natural gas transportation tariff is not fair or reasonable given the alleged existence of serious flaws in the administrative acts resulting from the proceedings for the last RTI established for TGS.

On April 28, 2021, ENARGAS submitted to TGS the 2021 Transitional Agreement ("RTT 2021"), which: (i) does not grant a transitory tariff update, keeping unchanged the tariff schemes approved by ENARGAS in April 2019; (ii) provides that, as from May 2021 and until the Final Renegotiation Agreement enters into effect, ENARGAS will recalculate the transportation tariffs effective at the time, with validity as from April 1, 2022.; (iii) does not establish a mandatory investment plan; and (iv) establishes the prohibition to distribute dividends, early cancel financial and commercial debts taken on with shareholders, acquire other companies, or grant loans.

On April 30, 2021 and through a note sent to this body, TGS expressed that, given the context in which it develops its activities and the proposed terms and conditions, it is not feasible for TGS to enter into the RTT 2021.

On June 2, 2021, ENARGAS issued Resolution No. 149/21 approving an RTT 2021 for TGS effective as from that date. Moreover, the National Ministry of Economy and ENARGAS issued Joint Resolution No. 1/21 approving the proceedings under the renegotiation process developed by ENARGAS pursuant to PEN Executive Order No. 1,020/20, stating that it was not feasible to reach an agreement on a transitional tariff update.

Given this situation, in July 2021, TGS filed motions for reconsideration, subsidiarity filing a hierarchical appeal, before the PEN, the National Ministry of Economy and ENARGAS according to the respective jurisdictions of each of these bodies in the passing of the regulations associated with Resolution No. 149/21, requesting the declaration of nullity of the RTT 2021 and the reinstatement of the RTI.

NOTE 2: (Continuation)

The challenges are based on: (i) the illegality of Executive Order No. 1,020/20, as it does not observe the delegation lines provided for by Act No. 27,541 and, as it does not meet the requirements established by the Constitution for the dictation of this regulation; (ii) the extension of the emergency period beyond that established by the Congress; (iii) the tariff renegotiation under Act No. 24,076 is not performed; (iv) the disregard for the principle of fair and reasonable tariffs, and the rights acquired by TGS under the license, the Contractual Adjustment Memorandum of Understanding and the RTI; and (v) the suspension of the RTI for reasons of public interest, which merits the recognition of the compensations provided for by both the Administrative Procedures Act and the License Basic Rules.

In turn, the restrictions on the management and administration of TGS have been challenged for lacking legal justification, as the emergency declared by Act No. 27,541 only empowered the PEN to renegotiate the RTI, but not the License. The challenges and the request for reinstatement of the RTI have been filed notwithstanding TGS's right to the payment of the compensations it is entitled to on account of the breach of the RTI as from April 2019.

On November 15, 2021, TGS filed a Prior Administrative Claim before ENARGAS and the Ministry of Economy. This presentation seeks to request compensation due to TGS for the non-application of the semi-annual adjustment methodology set by the RTI and approved by Resolution 4,362 between October 1, 2019 and June 1, 2021.

Moreover, TGS seeks compensation for the damages sustained by the freeze resulting from the failure to apply the semi-annual adjustment methodology set by the RTI for this period.

On January 19, 2022, a new public hearing was held within the framework of ENARGAS Resolution No. 518/21 to address the transition tariff update under PEN Executive Order No. 1020/20. In this hearing, aiming to reach a final agreement and restore the economic and financial equation, TGS requested a transition tariff adjustment in two stages for 2022 for a total of 106%, given the evolution of operating costs and the main macroeconomic indicators.

Later, on February 1, 2022, TGS received from ENARGAS the proposed Renegotiation Transition Agreement (the "RTT 2022"), which was approved by TGS's Board of Directors on February 2, 2022, and by the applicable governmental bodies on February 18, 2022. The RTT 2022 included certain terms similar to the RTT 2021, with the specific provision that it granted TGS a 60% tariff increase effective from March 1, 2022.

The RTT 2022 was ratified through PEN Executive Order No. 91/22, effective from February 23, 2022. On February 25, 2022, ENARGAS Resolution No. 60/22 was published in the BO, launching the tariff schemes contemplated in the RTT 2022.

NOTE 2: (Continuation)

It is worth highlighting that, as provided in the RTT 2022, TGS undertook not to initiate new claims, remedies, lawsuits, or any kind of actions; and/or to suspend, keep suspended or extend the suspension of all claims and remedies associated in any way with the current RTI renegotiation, Law No. 27,541, Decrees No. 278/20 and No. 1,020/20.

On December 7, 2022, ENARGAS issued Resolution No. 523/22 calling for a public hearing, to be held on January 4, 2023, to consider the transitional tariff update for the natural gas transportation utility.

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

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

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

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

2.3.2 License extension request

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

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

NOTE 2: (Continuation)

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

2.3.3.1 Domestic market

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

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

In this context, TGS sells the production of propane and butane to fractionators at prices determined semiannually. On March 30, 2015, the PEN issued Decree No. 470/15, regulated by SE Resolution No. 49/15, which created the "Household Plan" and sets a maximum reference price for the members of the commercialization chain in order to guarantee the supply to low-income residential user, by committing the GLP producers to supply at a fixed price with a quota assigned to each producer. Initially, a payment of compensation to the Household Plan participating producers was established, which was eliminated as from February 2019.

TGS has filed various administrative and judicial claims challenging the general regulations of the program, as well as the administrative acts that determine the volumes of butane that must be sold in the domestic market, in order to safeguard its economic-financial situation and thus, preventing that this situation does not extend over time.

In addition, TGS is a party of the Propane Gas Supply Agreement for Induced Propane Gas Distribution Networks ("Propane for Networks Agreement") entered into with the Argentine Government and propane producers by which it undertakes to supply propane to induced propane gas distributors and sub- distributors through at a price lower than the market price. In compensation, TGS receives an economic compensation calculated as the difference between the sale price and the export parity determined by the SE.

As it has been previously mentioned, participation in the Household Plan results in economic and financial damage to TGS, since under certain circumstances products would be sold at prices below their production costs.

As of December 31, 2023, the Argentine Government owes TGS $ 4,676 million under these items.

2.3.3.2 Foreign market

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

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

2.4 Transmisión

2.4.1 Transener and Transba tariff situation

On February 25, 2022, the ENRE communicated Resolutions No. 68/22 and 69/22 approving the new hourly remuneration values effective from February 1, 2022, establishing a 25% and 23% increase compared to the values effective from 2019 for Transener and Transba, respectively. Considering the difference between the presented financial and economic projections and the values finally approved by the ENRE, a motion to review the records and the respective preliminary challenges was submitted. Moreover, on March 15, 2022, the applicable motions for reconsideration against these resolutions were filed. Consequently, under Resolutions No. 147/22 and 148/22, on May 9, 2022 the ENRE partially upheld the filed motions and modified the hourly remuneration values effective from February 1, 2022, establishing a 67% and 69% increase over the values effective from August 2019 for Transener and Transba, respectively.

NOTE 2: (Continuation)

Since August 2022, Transener and Transba filed notes and held meetings with the SE and the ENRE requesting an update to the transitional tariffs effective from September 2022, chargeable against the increase to be assessed for 2023. To this effect, the 2023 economic and financial projection was presented with an explanatory document and a detail of the projected investment plan. Moreover, a presentation was made to CAMMESA's Board of Directors to put the criticality of the transportation sector on record.

Under Resolution No. 539/2022, on October 20, 2022 the ENRE called for a public hearing on November 30, 2022 to inform of and gather feedback on the electricity transmission utility concessionaires' proposals towards a transitional tariff update under the RTI Renegotiation Process before defining the tariffs applicable by the concessionaires.

Furthermore, on December 6, 2022, PEN Executive Order No. 815/22 extended for one-year term PEN Executive Order No. 1,020/20 published on December 17, 2020, through which initiated RTI renegotiation within up to 2 years from its publication.

Later, on December 29, 2022, aiming to preserve in 2023 the purchasing power of the revenues established in Resolutions No. 147/22 and 148/22, the ENRE issued Resolutions No. 698/22 and 702/22 setting the hourly remuneration values effective from January 1, 2023, and establishing a 154.5% and 154.1% increase over the February 2022 values for Transener and Transba, respectively.

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

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

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

NOTE 2: (Continuation)

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

Consequently, on January 2, 2024, through ENRE Resolution No. 3/24, a Public Hearing was called, which was held on January 29, 2024, in order to to inform of and gather feedback on the electricity transmission utility concessionaires' proposals towards a transitional tariff update under the RTI Renegotiation Process before defining the tariffs applicable by the concessionaires.

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

2.5 Regulations on access to the MLC

In 2020, BCRA introduced measures with the purpose of regulating inflows and outflows in the MLC to maintain the exchange rate stability and protect international reserves in view of the high degree of uncertainty and volatility in the exchange rate, including restrictions associated with transactions with stock market assets by companies and the disposal of liquid foreign assets. Specifically, as from December 11, 2023, any demand for foreign currency at the MLC requires BCRA's prior authorization.

NOTE 2: (Continuation)

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

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

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

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

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

On its part, the BCRA extended the obligation to submit a refinancing plan for certain debts and principal maturities scheduled up to December 31, 2023, based on the following criteria: (i) access to the MLC for up to 40% of the principal amount, in the original term; and (ii) the refinancing of the principal balance, with new foreign indebtedness with an average maturity of 2 years. Within the framework of this refinancing process, access to the MLC is allowed for the early cancellation of principal, interest or debt swaps up to 45 calendar days before the maturity date, provided all requirements set forth by the regulation have been verified. Likewise, the BCRA accepts access to the MLC for the cancellation of financial indebtedness abroad (provided they are not related parties) during the month of December 2023 as from the payable principal or interest's maturity date. Access is also possible up to 3 business days before the maturity date if the payment is made by means of an exchange and/or arbitration against a local foreign-currency account held by the customer authorized to make such payment.

NOTE 2: (Continuation)

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

Finally, the BCRA introduced adjustments to foreign exchange regulations establishing, among other provisions, access to the MLC for subjects obtaining certifications under currency access systems for the incremental production of oil and/or natural gas pursuant to PEN Executive Order No. 277/22 (see Note 2.2.3), for up to the amount of each certification, to be allocated to the payment of: (i) principal and interest of commercial or financial liabilities abroad, including liabilities with non-resident affiliates, (ii) earnings and dividends for closed and audited balance sheets; and/or (iii) the repatriation of direct investments by non-residents. RADPIP and/or RADPIGN beneficiaries must appoint a single domestic financial entity responsible for issuing such certifications and recording the amounts recognized by the SE and the applicable period.

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

NOTE 2: (Continuation)

2.6 Tax regulations - Main tax reforms

Pursuant to Law No. 27,430, Law No. 27,541, Law No. 27,630, and Law No. 27,701 several modifications were introduced in the tax treatment, the key components of which are described below:

2.6.1 Income tax

2.6.1.1 Income tax rate

Pursuant to Law No. 27,430, the income tax rate for Argentine companies would be gradually reduced from 35% to 30% for fiscal years beginning from January 1, 2018 to December 31, 2019, and to 25% for fiscal years beginning on or after January 1, 2020. However, Law No. 27,541 suspended the tax rate reduction planned for fiscal year 2020, keeping the rate at 30%.

On June 16, 2021, Law No. 27,630 was published in the BO, which modified the income tax rate effective for fiscal years starting as from January 1, 2021 inclusive. This modification provides for the application of a tiered rate scheme and, if applicable, a fixed tax according to the accumulated net taxable income tier: (i) for accumulated net income of up to $ 5 million, it establishes a 25% rate; (ii) for accumulated net income between $ 5 and $ 50 million, it establishes a fixed tax of $1.25 million plus a 30% rate over the surplus of $ 5 million; and (iii) for accumulated net income above $ 50 million, it establishes a fixed tax of $ 14.75 million plus a 35% rate over the surplus of $50 million. The accumulated net income amount is adjusted yearly, as from January 1, 2022, taking into consideration the annual CPI variation published by the INDEC.

The effect of the changes on deferred tax corresponding to comparative periods pursuant to the above-mentioned tax reform was recognised, considering the effective rate expected to be applicable at deferred assets and liabilities realization year, in "Effect of tax rate change in the deferred tax" under "Income tax" of the Consolidated Statement of Comprehensive Income (Note 10.6).

On August 16, 2022, AFIP's General Resolution No. 5,248/22 was published in the BO, whereby the AFIP established a one-time income tax prepayment by taxpayers and responsible persons listed in Section 73 of Law No. 20,628, as amended, meeting the following parameters: (i) an assessed tax for the 2021 or 2022 tax period of at least $ 100 million, or (ii) taxable income, without deducting accumulated tax losses, of at least $ 300 million. The Company and its subsidiaries paid an income tax prepayment for $ 1,863 million for the year 2022.

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

NOTE 2: (Continuation)

2.6.1.2 Tax on dividends

Law No. 27,430 and modifications introduced by Law No. 27,541 and Law No. 27,630, established a 7% tax on dividends derived from earnings accrued during fiscal years beginning as from January 1, 2018, which be distributed by Argentine companies to individuals, undivided estates or beneficiaries residing abroad.

Dividends resulting from benefits gained until the fiscal year prior to that beginning on January 1, 2018 will remain subject to the 35% withholding on the amount exceeding the untaxed distributable retained earnings (equalization tax' transition period) for all beneficiaries.

2.6.1.3 Tax inflation adjustment

Law No. 27,430 sets out the following rules for the application of the income tax inflation adjustment mechanism:

(i)	a cost adjustment for goods acquired or investments made during fiscal years beginning after January 1, 2018 taking into consideration the percentage variations in the CPI published by the INDEC; and

(ii)	the application of the adjustment provided for by Title VI of the Income Tax Law when variations in the above-mentioned index exceed 100% over the 36 months preceding the closing of the fiscal period to be settled.

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

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

NOTE 2: (Continuation)

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

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

2.6.2 Value-added tax

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

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

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

PAIS tax exemption for import transactions

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

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

i)	liquid fuels, natural gas and electricity;

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

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

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

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

2.6.4 Export Increase Program

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

NOTE 2: (Continuation)

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

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

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

NOTE 3: BASIS OF PREPARATION

These Consolidated Financial Statements have been prepared in accordance with IFRS´ Accounting Standards issued by IASB, are expressed in million dollars and were approved for their issuance by the Board of Directors on March 6, 2024. Significant accounting policies adopted in the preparation of these Consolidated Financial Statements are described in Note 4, which have been consistently applied.

This consolidated financial information has been prepared under the historical cost convention, modified by the measurement of financial assets at fair value through profit or loss.

These accounting policies have been applied consistently by all Group companies. Additionally, certain non-significant reclassifications have been made to financial statements presented with comparative purposes to keep the consistency in the presentation with the amounts of the current year.

NOTE 4: ACCOUNTING POLICIES

The main accounting policies used in the preparation of these Consolidated Financial Statements are explained below.

Pursuant to CNV General Resolution No. 972/23, the early application of IFRS´ Accounting Standards and/or their amendments is not allowed, unless specifically allowed at the time of adoption.

As of December 31, 2023, the Company has not opted for the early application of IFRS´ Accounting Standards and/or its amendments.

4.1 New accounting standards, amendments and interpretations issued by the IASB effective as of December 31, 2023 and adopted by the Company

The Company has applied the following standards and/or amendments for the first time as of January 1, 2023:

-	IFRS 17 - "Insurance Contracts" (issued in May 2017 and later amended in June 2020 and December 2021)

-	IAS 1 - "Presentation of financial statements" (amended in February 2021)

-	IAS 8 - "Accounting Policies" (amended in February 2021)

-	IAS 12 - "Income Taxes" (amended in May 2021 and May 2023)

The application of the detailed standards and amendments did not have any impact on the results of the operations or the financial position of the Company.

4.2 New standards, amendments and interpretations issued by the IASB not yet effective and which have not been early adopted by the Company

- IFRS 16 - "Leases": amended in September 2022. It incorporates amendments on sale and leaseback transactions. Amendments are applicable to fiscal years starting on or after January 1, 2024, allowing for early adoption. Their application will not have a significant impact on the Company's operating results or financial position.

- IAS 1 - "Presentation of financial statements": amended in January 2020, July 2020 and October 2022. It incorporates amendments to the classification of liabilities as current or non-current and provides clarification on treatment to be given to liabilities with covenants. Amendments are applicable to fiscal years starting on or after January 1, 2024, allowing for early adoption. Their application will not have a significant impact on the Company's operating results or financial position.

-IAS 7 - "Statement of Cash Flows" and IFRS 7 - "Financial instruments - disclosures": amended in May 2023. It incorporates disclosure requirements for information on financing agreements with suppliers to assess the effects of such agreements on liabilities, cash flows and exposure to liquidity risk. Amendments are applicable to fiscal years starting on or after January 1, 2024, allowing for early adoption. Their application will not have a significant impact on the Company's operating results or financial position.

NOTE 4: (Continuation)

-IAS 21 - Effects of changes in foreign exchange rates: amended in August 2023. It incorporates the accounting treatment in the event of lack of currency convertibility, establishing the guidelines for estimating the exchange rate to reflect the rate at which each transaction would take place at the measurement date, with the prevailing economic conditions. Amendments are applicable to fiscal years starting on or after January 1, 2025, allowing for early adoption. The Company is analyzing the foreign exchange context to evaluate the lack of currency convertibility and, if applicable, the impact of its application on the Company's operating results and financial position.

4.3 Effects of changes in foreign exchange rates

4.3.1 Functional and presentation currency

The information included in these Consolidated Financial Statements is recorded in U.S. dollars, which is the Company's functional currency, that is, the currency of the primary economic environment where the entity operates.

4.3.2 Foreign-currency transactions and balances

Foreign currency transactions are translated into the functional currency at the exchange rates prevailing on each transaction date or valuation date, when items are remeasured. Foreign exchange gains and losses arising on the settlement of monetary items and on translating monetary items at the closing of the fiscal year using year-end exchange rate are recognised within the financial results in the statement of comprehensive income, with the exception of capitalized amounts.

4.3.3 Group entities' translation into functional currency

The results and financial position of subsidiaries, joint ventures and associates whose functional currency is the Argentine Peso, a currency of a hyperinflationary economy, are translated into the Company's functional currency using the year-end exchange rate. The results generated by the application of IAS 29 adjustment mechanism for hyperinflationary economies, on the opening equity measured in functional currency are recognised under "Other comprehensive income".

4.3.4 Presentation of Other comprehensive income within the Company's equity

The Company classifies and directly accumulates within equity, in the retained earnings line, the results generated by the application of the IAS 29 adjustment mechanism on the opening retained earnings, while the remaining results are presented in a separate component of equity and accumulated until the disposal of the foreign operation in "Other comprehensive income", in accordance with IAS 21.

NOTE 4: (Continuation)

4.4 Principles of consolidation and equity accounting

4.4.1 Subsidiaries

Subsidiaries are all entities over which the Group has control. The Group controls an entity when the Group is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power to direct the activities of the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Group. The Group ceases consolidation of entities from the date that control ceases.

The acquisition method of accounting is used to account for business combinations by the Group (see Note 4.4.5 below).

Intercompany transactions, balances and unrealized gains on transactions between Group entities are eliminated. Unrealized losses are also eliminated unless the transaction provides evidence of an impairment of the transferred asset. Accounting policies of subsidiaries have been changed when necessary to ensure consistency with the policies adopted by the Group.

Non-controlling interests in the results and equity of subsidiaries are shown separately in the Consolidated Statement of Comprehensive Income and Consolidated Statement of Changes in Equity respectively.

4.4.2 Associates

Associates are all entities over which the group has significant influence but not control or joint control. This is generally the case where the Group holds between 20% and 50% of the voting rights. Investments in associates are accounted for using the equity method of accounting (see Note 4.4.4 below), after initially being recognised at cost.

4.4.3 Joint arrangements

Investments in joint arrangements are classified as either joint operations or joint ventures, according to IFRS 11, depending on the contractual rights and obligations of each investor. The Company participates both joint operations and joint ventures.

4.4.3.1 Joint operations

The Company recognizes its direct right to the assets, liabilities, incomes and expenses of joint operations and its share of any jointly held or incurred assets, liabilities, incomes and expenses. These have been incorporated in the Consolidated Financial Statements under the appropriate headings.

NOTE 4: (Continuation)

4.4.3.2 Joint ventures

Interests in joint ventures are accounted for using the equity method, after initially being recognised at cost (see Note 4.4.4 below).

4.4.4 Equity Method

Under the equity method of accounting, the investments are initially recognised at cost and adjusted to recognize the Group's share of the post-acquisition profits or losses and in other comprehensive income of the investee.

On acquisition of the investment, any difference between the cost of the investment and the entity's share of the net fair value of the investee's identifiable assets and liabilities is accounted for as follows: (i) goodwill relating to an associate or a joint venture is included in the carrying amount of the investment and is not amortised, and (ii) any excess of the net fair value over the cost is included as income in the determination of the entity's share of the associate or joint venture's profit or loss.

Dividends received or receivable from associates and joint ventures are recognised as a reduction in the carrying amount of the investment.

When the Group's share of losses in an equity-accounted investment equals or exceeds its interest in the entity, together with any long-term interests that, in substance, form part of the net investment, the Group does not recognize further losses, unless it has incurred obligations or made payments on behalf of the other entity.

Unrealized gains on transactions between the Group and its associates and joint ventures are eliminated to the extent of the group's interest in these entities. Unrealized losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred. Accounting policies of equity accounted investees have been changed where necessary to ensure consistency with the policies adopted by the Group.

The carrying amount of equity accounted investments is tested for impairment in accordance with the policy described in Note 4.9.

4.4.5 Business combinations

The acquisition method of accounting is used to account for all business combinations, regardless of whether equity instruments or other assets are acquired. The consideration transferred for the acquisitions comprises:

(i)	the fair value of the transferred assets,

(ii)	the liabilities incurred to the former owners of the acquired business,

(iii)

the equity interests issued by the group,

(iv)	the fair value of any asset or liability resulting from a contingent consideration arrangement, and

(v)	the fair value of any pre-existing equity interest in the subsidiary.

NOTE 4: (Continuation)

Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values in the acquisition date. The group recognises any non-controlling interest in the acquired entity on an acquisition-by-acquisition basis at the non-controlling interest's proportionate share of the acquired entity's net identifiable assets.

Acquisition-related costs are expensed as incurred. The value of the goodwill represents the excess of: i) the consideration transferred, ii) the amount of any non-controlling interest in the acquired entity, and iii) the acquisition-date fair value of any previous equity interest in the acquired entity, over the fair value of the net identifiable assets acquired is recorded as goodwill. If the fair value of the net identifiable assets of the business acquired exceeds those amounts, the gain on bargain purchase is recognised directly in profit or loss.

Contingent consideration is classified either as equity or a financial liability. Amounts classified as a financial liability are subsequently remeasured to fair value with changes in fair value recognised in profit or loss.

If the business combination is achieved in stages, the acquisition date carrying value of the acquirer's previously held equity interest in the acquiree is remeasured to fair value at the acquisition date. Any gains or losses arising from such remeasurement are recognised in profit or loss.

The Group has up to 12 months to finalize the accounting for a business combination. Where the accounting for a business combination is not complete by the end of the year in which the business combination occurred, the Group reports provisional amounts.

4.4.6 Changes in ownership interests

The Group treats transactions with non-controlling interests that do not result in a loss of control as transactions with equity owners of the group. A change in ownership interest results in an adjustment between the carrying amounts of the controlling and non-controlling interests to reflect their relative interests in the subsidiary. Any difference between the amount of the adjustment to non-controlling interests and any consideration paid or received is recognised in "Other reserves" within equity attributable to owners of the Company.

NOTE 4: (Continuation)

When the Group ceases to consolidate or equity account for an investment because of a loss of control, joint control or significant influence, any retained interest in the entity is remeasured to its fair value with the change in carrying amount recognised in profit or loss. This fair value becomes the initial carrying amount for the purposes of subsequently accounting for the retained interest as an associate, joint venture or financial asset. In addition, any amounts previously recognised in other comprehensive income in respect of that entity are accounted for as if the Group had directly disposed of the related assets or liabilities, this means that amounts previously recognised in other comprehensive income are reclassified to profit or loss.

If the ownership interest in a joint venture or an associate is reduced but joint control or significant influence is retained, only a proportionate share of the amounts previously recognised in other comprehensive income are reclassified to profit or loss where appropriate.

4.5 Segment reporting

Operating segments are reported in a manner consistent with the internal reporting provided to the Executive committee.

The Executive Committee, is the highest decision-making authority, is the person responsible for allocating resources and setting the performance of the entity's operating segments and has been identified as the body executing the Company's strategic decisions.

In segmentation the Company considers transactions with third parties and intercompany operations, which are done on internal transfer pricing based on market prices for each product.

4.6 Property, plant and equipment

Property, Plant and Equipment is measured following the cost model. It is recognised at acquisition cost less depreciation a less any accumulated impairment.

Subsequent costs are included in the asset's carrying amount or recognised as a separate asset, as appropriate, only when it is probable that future economic benefits associated with the item will flow to the group and the cost of the item can be measured reliably. The carrying amount of any component accounted for as a separate asset is derecognised when replaced. All other repairs and maintenance are charged to profit or loss during the reporting period in which they are incurred.

Works in progress are valued according to their degree of progress. The cost of work in progress whose construction will extend over time includes, if applicable, the computation of financial costs accrued on loans granted by third parties and other pre-production costs. Revenues and costs arising from the sale of elements obtained during the start-up process are charged to the profit and loss of the period.

NOTE 4: (Continuation)

Assets' residual values and useful lives are reviewed, and adjusted if appropriate, at the end of each year. An asset's carrying amount is written down immediately to its recoverable amount if the asset's carrying amount is greater than its estimated recoverable amount.

Gains and losses on disposals are determined by comparing the sale price with the carrying amount, stated in terms of the measuring unit current at the disposal date.

4.6.1 Depreciation methods and useful lives

The group depreciates productive wells, machinery and camps in the oil and gas production areas according to the units of production method, by applying the ratio of oil and gas produced to estimated proved developed oil and gas reserves. The acquisition cost of property with proved reserves is depreciated by applying the ratio of oil and gas produced to estimated proved oil and gas reserves. Acquisition costs related to properties with unproved reserves is valued at cost with recoverability periodically assessed on the basis of geological and engineering estimates of possible and probable reserves that are expected to be proved over the life of each concession.

Machinery and generation equipment (including any significant identifiable component) are depreciated under the unit of production method.

The group´s remaining items of property, plant and equipment (including any significant identifiable component) are depreciated by the straight-line method based on estimated useful lives, as detailed below:

Buildings:	50 years
Vehicles:	3 - 5 years
Furniture, fittings and communication equipment:	5 years
Computer equipment and software:	3 years
Tools:	10 years
Equipment and machinery:	10 - 30 years

If appropriate, the depreciation method is reviewed and adjusted at the end of each year.

4.6.2 Asset retirement obligations and wind turbines decommissioning

Estimated future costs of asset retirement obligations on well abandonment in oil and gas areas and wind turbines decommissioning in wind farms, discounted at a risk adjusted rate, are capitalized in the cost of the assets and depreciated using the units of production method. Additionally, a liability at the estimated value of the discounted amounts payable is recognised. Changes in the measurement of asset retirement obligations that result from changes in the estimated timing, amount of the outflow of resources required to settle the obligation, or the discount rate, are added to, or deducted from, the cost of the related asset. If a decrease in the liability exceeds the carrying amount of the asset, the excess is recognised immediately in profit or loss.

NOTE 4: (Continuation)

4.7 Intangible assets

4.7.1 Goodwill

Goodwill is the result of the acquisition of subsidiaries. Goodwill represents the excess of the acquisition cost over the fair value of the equity interest in the acquired entity held by the company on the net identifiable assets acquired on the date of acquisition.

For impairment testing, goodwill acquired in a business combination is allocated from the acquisition date to each of the CGU or group of CGU that are expected to benefit from the synergies of the combination. Each unit or group of units that goodwill is allocated represents the lowest level within the entity at which the goodwill is monitored for internal management purposes.

4.7.2 Concession arrangements

Concession arrangements corresponding to hydroelectric generation plants Diamante and Nihuiles are not under the scope of the guidelines of IFRIC 12 "Service Concession Arrangements".

These concession agreements meet the criteria set forth by the IFRS´ Accounting Standards for capitalization less depreciation a less any accumulated impairment. They are amortized following the straight-line method based on useful life, which corresponds to the life of each concession agreement.

4.7.3 Identified intangible assets in acquired investments

Corresponds to intangible assets identified in the moment of the acquisition of companies. Identified assets meet the criteria established in IFRS´ Accounting Standards for capitalization less depreciation and less any accumulated impairment. They are amortized by the straight-line method according to the useful life of each asset, considering the estimated way in which the benefits produced by the asset will be consumed.

4.7.4 Digital Assets

The Company accounts for digital assets (cryptocurrencies) as intangible assets with indefinite useful life under the cost model. They are recognised at acquisition cost less any accumulated impairment.

4.8 Assets for oil and gas exploration

The Company uses the successful efforts method of accounting for its oil and gas exploration and production activities. This method involves the capitalization of: (i) the cost of acquiring properties in oil and gas exploration and production areas; (ii) the cost of drilling and equipping exploratory wells that result in the discovery of commercially recoverable reserves; (iii) the cost of drilling and equipping development wells, and (iv) the estimated asset retirement obligations (see Note 4.6.2).

NOTE 4: (Continuation)

According to the successful efforts method of accounting, exploration costs (including geological and geophysical costs), excluding exploratory well costs, are expensed during the period in which they are incurred. Drilling costs of exploratory wells are capitalized until it is determined that proved reserves exists and they justify the commercial development. If reserves are not found, such drilling costs are expensed. Occasionally, an exploratory well may determine the existence of oil and gas reserves but they cannot be classified as proved when drilling is complete. In those cases, such costs continue to be capitalized insofar as the well has allowed determining the existence of sufficient reserves to warrant its completion as a production well and the Company is making sufficient progress in evaluating the economic and operating feasibility of the project.

4.9 Impairment of non-financial long-lived assets

Intangible assets that have an indefinite useful life and goodwill are not subject to amortization and are tested annually for impairment, or more frequently if events or changes in circumstances indicate that they might be impaired.

The remaining non-financial long-lived assets are tested for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the asset's carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset's fair value less costs of disposal and value in use. For the purpose of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows which are largely independent of the cash inflows from other assets or groups of assets (CGU).

Non-financial long-lived assets, other than goodwill, that have been impaired are reviewed for possible reversal of the impairment at the end of each reporting period.

4.10 Financial assets

4.10.1 Classification

Based on the entity's business model for managing the financial assets and the contractual cash flow characteristics, the Group classifies its financial assets in the following categories:

(i)	those that are subsequently measured at fair value through profit or loss, and

(ii)	those that are subsequently measured at amortised cost.

The company reclassifies financial assets when and only when it changes its business model for managing those financial assets.

NOTE 4: (Continuation)

4.10.2 Recognition and derecognition

The conventional purchases and sales of financial assets are accounted for at settlement date. Financial assets are derecognised when contractual rights to the cash flows from the financial assets have expired or been transferred, and the Company has substantially transferred all risks and rewards of ownership of the asset.

4.10.3 Measurement

At initial recognition, the Group measures a financial asset at its fair value plus, in the case of a financial asset not at fair value through profit or loss, transaction costs that are directly attributable to the acquisition of the financial asset.

A gain or loss on a debt investment that is subsequently measured at fair value and is not part of a hedging relationship is recognised in profit or loss and disclosed in "Changes in the fair value of financial instruments" within "Other financial Results. A gain or loss on a debt investment that is subsequently measured at amortized cost and is not part of a hedging relationship is recognised in profit or loss when the financial asset is derecognised or impaired and through the amortization process using the effective interest rate method.

The Group subsequently measures equity investments at fair value through profit or loss. Dividends from such investments continue to be recognised in profit or loss as long as they represent a return on investment.

4.10.4

Impairment of financial assets

The Company assesses the expected credit losses related to its financial instruments at amortized cost and financial instruments at fair value through other comprehensive income, if applicable.

The Company applies the simplified approach allowed by IFRS 9 to measure expected credit losses for trade receivables and other receivables with similar risk characteristics. For this purpose, receivables are grouped by business segment and based on shared credit risk characteristics and expected credit losses are determined based on rates calculated for different ranges of default days from the due date.

The expected loss rates are based on the sales collection profiles over a period of 24 months before the end of each year, considering historical credit losses experienced within this period that are adjusted, if applicable, to reflect forward-looking information that could affect the ability of customers to settle the receivables.

NOTE 4: (Continuation)

4.10.5 Offsetting of financial instruments

Financial assets and liabilities are offset, and the net amount reported in the consolidated statements of financial position, when there is a legally enforceable right to offset the recognised amounts, and there is an intention to settle on a net basis, or realize the asset and settle the liability simultaneously.

4.11 Trade and other receivables

Trade receivables and other receivables are recognised at fair value and subsequently measured at amortized cost, using the effective interest method, less provision for impairment, if applicable.

The Company recognizes provisions for impairment on trade and other receivables based on expected credit loss model described in Note 4.10.4. Trade receivables are written off when there is no reasonable expectation of recovery. The Company considers the following default indicators: i) voluntary reorganization proceedings, bankruptcy or initiation of judicial demands; ii) insolvency implying a high impossibility of collection and iii) past due balances greater than 90 days.

Where applicable, provisions for impairment on tax credits have been recognised based on estimates on their uncollectibility within their statutory limitation period, taking into consideration the Company's current business plans.

4.12 Derivative financial instruments and hedging account

Derivative financial instruments are measured at fair value, determined as the amount of cash to be collected or paid to settle the instrument as of the measurement date, net of any prepayment collected or paid. Fair value of derivative financial instruments traded in active markets is disclosed based on their quoted market prices and fair value of instruments that are not traded in active markets is determined using different valuation techniques. Subsequent accounting of changes in fair value depends on whether the derivative is designated as a hedging instrument and, if so, the nature of the item being hedged.

The Company has not formally designated financial instruments as hedging instruments.

4.13 Inventories

This line item includes crude oil stock, raw materials, work in progress and finished products relating to Petrochemicals and Oil and Gas business segments as well as materials and spare parts relating to the Generation business segment.

Inventories are stated at the lower of cost or net realizable value. Cost is determined using the weighted average price method. The cost of inventories includes expenditure incurred in purchases and production and other necessary costs to bring them to their existing location and condition. In case of manufactured products and production in process, the cost includes a portion of indirect production costs, excluding any idle capacity (slack).

The net realizable value is the estimated selling price in the ordinary course of business less the estimated cost of completion and the estimated costs to make the sale.

NOTE 4: (Continuation)

The assessment of the recoverable value of these assets is made at each reporting date, and the resulting loss is recognised in the statement of income when the inventories are overstated.

The Company has classified materials and spare parts into current and non-current, depending on the timing in which they are expected to be used for replacement or improvement on existing assets. The portion of materials and spare parts for maintenance or improvements on existing assets, is exposed under the heading "Property, plant and equipment".

4.14 Non-current assets (or disposal group) held for sale and discontinued operations

Non-current assets are classified as held for sale if it is considered highly probable that their amount will be recovered through a sale transaction. They are measured at the lower of their carrying amount and fair value less costs to sell, except deferred tax assets, assets arising from employee benefits, financial assets and investment property that are carried at fair value and contractual rights from insurance contracts, which are specifically exempt from this requirement.

Non-current assets (including those that are part of a disposal group) are not depreciated or amortized while they are classified as held for sale. Interest and other expenses attributable to the liabilities of a disposal group classified as held for sale continue to be recognised.

Non-current assets or group of assets classified as held for sale are presented separately from the other assets in the balance sheet. The liabilities of a disposal group classified as held for sale are presented separately from other liabilities in the balance sheet. These assets and liabilities are not offset.

If it is a discontinued operation, that is, an item which has been disposed of or classified as held for sale; and (i) it represents a significant business line or geographic area which may be considered separate from the rest; (ii) it is part of a single coordinated plan to dispose of a significant business line or operating geographic area which may be deemed separate from the rest; or (iii) it is a subsidiary entity acquired solely for the purpose of reselling it; a single amount is disclosed in the statement of comprehensive income, which shows results of discontinued operations, net of tax, including the result for the valuation at fair value less cost of sales or asset disposal costs, if applicable.

4.15 Cash and cash equivalents

For the purpose of presentation in the Consolidated Statement of Cash Flows, cash and cash equivalents includes cash on hand, deposits held at call with financial institutions, other short-term, highly liquid investments with original maturities of three months or less that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value. If any, bank overdrafts are shown within borrowings in current liabilities, this means, there are not disclosed under Cash and cash equivalents in the Consolidated Statement of Cash Flows since they are not part of the Company's cash management.

NOTE 4: (Continuation)

4.16 Shareholder´s equity

Equity's movements accounted for in accordance with the pertinent decisions of shareholders' meetings and legal or regulatory standards.

All equity accounts have been restated in terms of the measuring unit current as of December 31, 2018, with the exception of Share capital and Treasury shares, which represent the subscribed and paid in, and the outstanding treasury capital, respectively. The adjustment resulting from its restatement as of December 31, 2018 is disclosed in the Comprehensive share capital adjustment and Comprehensive treasury shares adjustment lines, respectively.

As from the change in functional currency, on January 1, 2019 the Company discontinued the preparation and presentation of financial statements under IAS 29, and has considered equity figures expressed in terms of the measuring unit current as of December 31, 2018 as the basis for subsequent financial statements' amounts.

4.16.1 Share capital

Share capital represents the capital issued, composed of the contributions that were committed and/or made by the shareholders and represented by shares that comprise outstanding shares at nominal value.

4.16.2 Share premium

It includes:

(i)	The portion of the collected price exceeding the face value of the shares issued by the Company, net of absorbed accumulated losses.

(ii)	The difference between the fair value of the consideration paid/collected and the accounting value of the equity interest in the subsidiary acquired/sold/diluted which does not represent a loss of control or significant influence.

(iii)

The difference between the proportional equity value registered before the merger of the subsidiary and the value resulting from applying to the subsidiary's merged equity interest, the new ownership share resulting from the exchange relationship.

4.16.3 Legal reserve

In accordance with the LGS, 5% of the profit arising from the statement of income for the year, prior years' adjustments, the translation differences which are directly accumulated in Retained earnings (see Note 4.3.4), the amounts transferred from other comprehensive income and prior years' accumulated losses, must be appropriated to a legal reserve until such reserve equals 20% of the Company's share capital and the related adjustment of share capital. When for any reason, the amount of this reserve is reduced, dividends may not be distributed, until such amount is reached.

NOTE 4: (Continuation)

4.16.4 Voluntary reserve

This reserve results from an allocation made by the Shareholders' Meeting, whereby a specific amount is set aside to cover for the funding needs of projects and situations associated with Company policies.

4.16.5 Other reserves

It includes the result of operations with non-controlling interest that do not result in a loss of control and reserves for stock compensation plans.

4.16.6 Retained earnings

Comprise accumulated profits or losses without a specific appropriation; positive earnings can be distributable by the decision of Shareholders' meeting, as long as they are not subject to legal restrictions. Earnings comprise current earnings, prior years' earnings that were not distributed, translation differences which are directly accumulated in retained earnings pursuant to the policy described in Note 4.3.4, the amounts transferred from other comprehensive income and prior years' adjustments, according to IFRS´ Acoounting Standards.

General Resolution No. 593/11 issued by the CNV provided that Shareholders in the Meetings at which they should decide upon the approval of financial statements in which the Retained earnings account has a positive balance, should adopt an express resolution as to the allocation of such balance, whether to dividend distribution, capitalization, setting up of reserves or a combination of these. The Company's Shareholders have complied with these requirements.

4.16.7 Other comprehensive income

It includes gains and losses from the remeasurement process of foreign operations and the translation differences which are not classified and directly accumulated in retained earnings pursuant to the policy described in Note 4.3.4 and actuarial gains and losses for defined benefit plans and the related tax effect.

4.16.8 Dividends distribution

Dividend distribution to Company shareholders is recognised as a liability in the year in which the dividends are approved by the Shareholders' Meeting. The distribution of dividends is made based on the Company's Stand-Alone Financial Statements, which are presented in pesos, the legal currency in Argentina, pursuant to regulatory requirements.

NOTE 4: (Continuation)

4.17 Compensation plans

The following guidelines under IFRS 2 have been taken into consideration for the registration of stock-based compensations:

4.17.1 Compensations payable in cash:

Compensation Agreements - Senior Management: fixed compensation and annual, variable and contingent long-term compensation established based on the Company's annual market value appreciation, with a payment cap calculated over the Company's adjusted operating income. Any analogous compensation paid to senior managers is deducted from the compensation amount.

The reasonable value of the received services is measured through a share appreciation estimate using the Black-Scholes-Merton financial valuation model. The fair value of the amount payable is accrued and acknowledged as an expense, with the corresponding increase in liabilities. Liabilities are revalued on each balance sheet date. Any change in the fair value of liabilities is disclosed under profit or loss.

4.17.2 Compensations payable in shares

Stock compensation plan by which certain officers and other key staff receive a certain number of the Company's shares. The Company's Board of Directors approves the market acquisition of own shares as a means of implementing the Plan (see Note 13.1.2).

The number of shares for each eligible employee is calculated as from a percentage over the total annual remuneration, including the bonus, divided by the weighted average price, in pesos, of the Company's share and ADR for the same period; with one-third vesting each year, which will be awarded together with the payroll for April of the year following the vesting date, with the requirement that the employment relationship continues at least until each vesting date. The fair value of the received services is measured at the fair value of the shares at the time of granting and is disclosed during the vesting period, together with the corresponding increase in equity.

4.18 Trade payables and other payables

Trade payables and other payables are recognised initially at fair value and subsequently measured at amortized cost using the effective interest method.

NOTE 4: (Continuation)

4.19 Borrowings

Borrowings are recognised initially at fair value, net of transaction costs incurred. Borrowings are subsequently measured at amortized cost. Any difference between the proceeds (net of transaction costs) and the redemption amount is recognised in profit or loss over the period of the borrowings, using the effective interest method.

Borrowings are removed from the statement of financial position when the obligation specified in the contract is discharged, canceled or expired. The difference between the carrying amount of a financial liability that has been extinguished or transferred to another party and the consideration paid, including any non-cash assets transferred or liabilities assumed, is recognised in profit or loss as other income or finance costs.

If a debt contract is amended or swapped, the Company records the cancellation of the original liability and discloses a new financial liability if the new conditions are substantially different from the original ones.

Borrowings are classified as current liabilities unless the group has an unconditional right to defer settlement of the liability for at least 12 months after the reporting period.

4.19.1 Borrowing costs

General and specific borrowing costs that are directly attributable to the acquisition, construction or assembly of a qualifying asset are capitalized during the period of time that is required to complete and prepare the asset for its intended use. Qualifying assets are assets that necessarily take a substantial period of time to get ready for their intended use.

Investment income earned on the temporary investment of specific borrowings pending their expenditure on qualifying assets is deducted from the borrowing costs eligible for capitalization.

Other borrowing costs are recorded in profit or loss for the period in which they are incurred.

4.20 Employee benefits

4.20.1 Short-term obligations

Payroll liabilities, including non-monetary benefits and accumulated sick leave expected to be settled in full within 12 months after the end of the reporting period in which the employees provide the associated service are recognised for the amount expected to be paid when the liabilities are settled. The liabilities are disclosed as Salaries and social security payable in the consolidated statement of financial position.

NOTE 4: (Continuation)

4.20.2 Defined benefit plans

Labor costs liabilities are accrued in the periods in which the employees provide the services that trigger the consideration.

Additionally, the Company operates several defined benefit plans. Defined benefit plans define an amount of pension benefit that an employee will receive on retirement, depending on one or more factors, such as age, years of service and compensation. In accordance with conditions established in each plan, the benefit may consist in a single payment, or in making complementary payments to those made by the pension system.

The defined benefit liability recognised in the financial statement balance sheet, at the end of the reporting period, is the present value of the defined benefit obligation net of the fair value of the plan assets, when applicable. The defined benefit obligation is calculated annually by independent actuaries using the projected unit credit method. The present value of the defined benefit obligation is determined by discounting the estimated future cash outflows using future actuarial assumptions about demographic and financial variables that affect the determination of the amount of such benefits.

Actuarial gains and losses from experience adjustments and changes in actuarial assumptions, are recognised in other comprehensive income (loss) in the period in which they arise and past service costs are recognised immediately in the statement of income (loss).

4.21 Provisions, contingent liabilities and contingent assets

Provisions are recognised when the group has a present legal or constructive obligation as a result of a past event, it is probable that an outflow of resources will be required to settle that obligation, and the amount can be reliably estimated. Provisions are not recognised for future operating losses.

Provisions are measured at the present value of the expenditures expected to be required to settle the present obligation, taking into account the best available information as of the date of the Consolidated Financial Statements based on assumptions and methods considered appropriate and taking into account the opinion of Company's legal advisors. As additional information becomes available to the Company, estimates are revised and adjusted periodically. The discount rate used to determine the present value reflects current market assessments of the time value of money and the risks specific to the liability, as of the date of the financial statements. The increase in the provision due to the passage of time is recognised within other financial results.

NOTE 4: (Continuation)

Contingent liabilities are possible obligations that arise from past events and whose existence will be confirmed only by the occurrence or non-occurrence of uncertain future events not wholly within the control of the entity; or present obligations that arise from past events but it is not probable that an outflow of resources will be required to its settlement; or whose amount cannot be measured with sufficient reliability.

Contingent liabilities are not recognised. The Company discloses in notes to the Consolidated Financial Statements a brief description of the nature of material contingent liabilities.

Contingent liabilities, whose possibility of any outflow in settlement is remote, are not disclosed unless they involve guarantees, in which case the nature of the guarantee is disclosed.

Contingent assets are possible assets that arise from past events and whose existence will be confirmed only by the occurrence or non-occurrence of uncertain future events not wholly within the control of the entity.

Contingent assets are not recognised. The Company discloses in notes to the Consolidated Financial Statements a brief description of the nature of material contingent assets, where the related inflows of economic benefits are estimated to be probable.

4.22 Revenue from contracts with customers

4.22.1 Generation segment:

4.22.1.1 Revenues from sales to the spot market (SE Resolution N°869/23)

The Company recognizes revenues from i) power availability on a monthly basis as the different power plants are available to generate; ii) power generated, operated energy and power generated in peak hours, when the delivery of energy is effective, based on the price applicable depending on the technology of each plant. Revenues are not adjusted for the effect of financing components as sales are made with an average credit term of 42 days, which is consistent with market practice.

4.22.1.2 Revenues from supply agreements with CAMMESA (SE Resolution No. 220/07, SE Resolution No. 21/16, SE Resolution No. 287/17 and Renovar Programs)

The Company recognizes revenues from supply contracts with CAMMESA for i) power availability, when applicable, on a monthly basis, as the different power plants are available to generate and ii) energy generated when the delivery of energy is effective, based on the price established in each contract. Revenues are not adjusted for the effect of financing components as sales are made with an average credit term of 42 days, which is consistent with market practice.

NOTE 4: (Continuation)

4.22.1.3 Revenues from sales contracts with large users within the MAT

The Company recognizes revenues from energy plus sales and renewable energy when the delivery of energy is effective based on the price established in each contract. Revenues are not adjusted for the effect of financing components as sales are made with an average credit term of 30 days, which is consistent with market practice.

4.22.2 Oil and gas segment

The Company recognizes revenues from the sale of oil and gas, to third parties and intersegment, when control of the product is transferred, that is, at the output of each area, when the oil and gas is delivered to the carrier and to the extent there is no unfulfilled obligation that could affect the acceptance of the product by the client. In all cases the transport of the gas is in charge of the client. Revenues from these sales are recognised based on the price by product specified in each contract or agreement to the extent that it is highly probable that a significant reversal will not occur.

Revenues are not adjusted for the effect of financing components as sales are made with an average credit term not exceeding 45 days, which is consistent with market practice.

4.22.3 Petrochemical segment

The Company recognizes revenues from the sale of petrochemical products, whether in local or foreign markets, when the control of the product is transferred, that is, when the products are delivered to the client and there is no unfulfilled obligation that could affect the acceptance of the product by the client. The delivery, as established in each contract, is occurs:

(i)	when the products are dispatched and transported by and in charge of the client, or,

(ii)

when the products have been dispatched by the Company to a specific location, the obsolescence risks and loss have been transferred to the client, and the client has accepted the products according to the sale contract, the acceptance provisions have expired, or when the Company has objective evidence that all acceptance criteria have been met.

Revenues from these sales are recognised based on the price specified in each contract, to the extent that it is highly probable that a significant reversal will not occur. Revenues are not adjusted for the effect of financing components as sales are made with an average credit term not exceeding 34 days, which is consistent with market practice.

NOTE 4: (Continuation)

4.22.4 Holding and others segment

The Company recognizes revenues from contracts with customers in relation to advisory services to related companies as services are rendered based on the price established in each agreement. Revenues are not adjusted for the effect of financing components, as sales are made with an average credit term of 30 days, which is consistent with market practice.

4.23 Other Income

4.23.1 Government grants

Grants from the government are recognised at their fair value where there is a reasonable assurance that the grant will be received and the Group will comply with all attached conditions. The group did not benefit directly from any other forms of government assistance.

The Company recognizes revenues from natural gas production promotion or stimulus programs upon the actual delivery of gas and in accordance with the price established in the applicable regulation, only inasmuch as it is highly probable that there will be no significant reversal and the consideration is likely to be received, that is, to the extent that the procedure established by the Government is formally complied with.

The recognition of revenues associated with Natural Gas Production Promotion or Stimulus Plans (see Note 2.2.4.1) falls within the scope of IAS 20 as it involves a compensation as a result of the maintenance or increase in the committed production volume.

Revenues from natural gas production or stimulus programs are disclosed under other operating income in the consolidated statement of comprehensive income. Furthermore, the fiscal costs of the above-mentioned programs are disclosed under Other operating expenses in the consolidated statement of comprehensive income.

4.23.2 Interest

Interest income from financial assets at fair value through profit or loss is included into the result of changes in the fair value of those assets. Interest income from financial assets at amortized are recognised in the statement of income.

Interest income is calculated by using the effective interest rate to the gross carrying amount of a financial asset (without considering impairment provision), except for impaired financial assets, that is calculated by applying the effective interest rate to the carrying amount net of impairment provision.

Commercial interest corresponding to late payment surcharges in the cancellation of sales receivables is disclosed under Other operating income as it provides relevant information on the business' operations and operating flows.

NOTE 4: (Continuation)

4.23.3 Dividends

Dividends income are received from financial assets measured at fair value through profit or loss. Dividends are recognised as revenue when the right to receive payment has been established. This applies even if they are paid out of pre-acquisition profits.

4.24 Income tax

The tax expenses for the year include current and deferred tax. Tax is recognised in the income statement, except to the extent that it relates to items recognised in other comprehensive income or directly in equity, in which case, the tax is also recognised in other comprehensive income or directly in equity, respectively.

The current income tax charge is calculated on the basis of the tax laws enacted or substantively enacted at the balance sheet. Management periodically evaluates positions taken in tax returns with respect to situations in which applicable tax regulation is subject to interpretation. It establishes provisions, where appropriate, on the basis of amounts expected to be paid to the tax authorities.

Deferred income tax is recognised, using the liability method on temporary differences between the tax bases of assets and liabilities and their carrying amounts in the Consolidated Financial Statements. However, deferred tax liabilities are not recognised if they come from the initial recognition of goodwill; or if it arises from initial recognition of an asset or liability in a transaction other than a business combination that at time of the transaction affects neither accounting nor taxable profit or loss, and does not give rise to equal taxable and deductible temporary differences.

Deferred income tax assets are recognised only to the extent that it is probable that future taxable profit will be available and can be used against temporary differences.

Deferred income tax is provided on temporary differences from investments in subsidiaries, joint ventures and associates, except for deferred income tax liability where the timing of the reversal of the temporary difference is controlled by the group and it is probable that the temporary difference will not reverse in the foreseeable future.

Deferred assets or liabilities are recognised on account of gains or losses from fiscal tax inflation which, pursuant to Law No. 27,541 and Law No 27,701, are deferred and accounted for in subsequent fiscal periods (see Note 2.6.1).

Deferred income tax assets and liabilities are offset when there is a legally enforceable right to offset the recognised amounts and when the deferred income tax assets and liabilities relate to income taxes levied by the same taxation authority on either the same taxable entity or different taxable entities where there is an intention to settle the balances on a net basis.

NOTE 4: (Continuation)

Current and deferred tax assets and liabilities have not been discounted and are stated at their nominal value.

Income tax rates prevailing at year-end in Argentina (see Note 2.6.1), Ecuador, Bolivia and Uruguay are 35%, 25%, 25% and 25%, respectively. Additionally, a 3% surcharge is added to Ecuador's income tax when the company's shareholder residing in Ecuador is an entity established in a jurisdiction considered a tax haven under Ecuadorian laws.

In Bolivia, payment of Bolivian-source income to beneficiaries outside Bolivia is levied with a 12.5% withholding income tax.

Furthermore, and pursuant to the last tax reform passed in Ecuador and effective as from January 1, 2020, dividends distributed to foreign shareholders will be subject to a 10% withholding.

In Uruguay, effective from January 1, 2023, the Income Tax on Economic Activities ("IRAE") includes as Uruguayan-source certain passive income derived by entities making up non-qualified multinational groups.

Deferred tax assets and liabilities are measured using the tax rates expected to apply in the period when the asset is realized or the liability is settled.

Finally, receivables have been disclosed on account of the application of the minimum presumed income tax prior to its abrogation as from January 1, 2019, which are computable as an advance payment of income tax in any of the following ten years.

The Company's management evaluates the recoverability of the recorded receivables at the closing of each fiscal year, and allowances are created as long as it is estimated that the computable amounts will not be recoverable within the statutory limitation period taking into consideration the Company's current business plans.

4.25 Leases

In leases where the Company is a lessee (Note 19.1), a right-of-use asset and a lease liability are recognised on the date on which the underlying asset is available for use by the Company.

At the commencement date the lease liability is measured at the present value of the payments that are not paid at that date, including:

-	fixed payments, less any lease incentive receivable

-	variable lease payments depending on an index or rate

-	amounts that the Company expects to pay under residual value guarantee

-	exercise price of a purchase option (if it is reasonably certain to exercise that option), and

-	penalty payments for terminating the lease (if that option will be exercised).

NOTE 4: (Continuation)

Lease payments are discounted using the Company's incremental borrowing rate, which is the rate the Company would have to pay to borrow over a similar term, security and conditions, the funds necessary to acquire an asset of a similar value to the right-of-use asset in a similar economic environment, or by using the interest rate implicit in the lease, if that rate can be readily determined.

The lease liability is disclosed in "Trade and other payables". Each lease payment is apportioned between the principal and the financial cost. The financial cost is charged to income over the term of the lease to produce a constant periodic interest rate on the remaining liability balance for each period.

Right-of-use assets are measured at cost, which comprises:

-	the amount of the initial measurement of the lease liability

-	any lease payment made at or before the commencement date, less any lease incentive received

-	any initial direct cost, and

-	an estimate of costs to be incurred for decommissioning or restoring the underlying asset pursuant to the terms and conditions of the lease

-	Right-of-use assets are depreciated using the straight-line method over the asset's useful life or, if shorter, during the lease term.

The Company recognizes lease payments associated with short-term leases (up to 12 months) and leases for which the underlying asset is of low value (IT equipment and office supplies) as an expense using the straight-line method over the lease term.

Leases in which the Company, as a lessor, has transferred all risks and rewards incidental to ownership of the underlying asset are classified as financial leases (Note 19.2.1). Financial leases are recognised at the commencement date at the fair value of the leased property or, if lower, the present value of the minimum lease payments to be received. The corresponding lease rights, net of financial charges, are included in "Trade and other receivables". Each lease payment received is allocated between income receivable and financial income. Financial income is recognised as a profit over the term of the lease to produce a constant periodic interest rate on the remaining liability balance for each period. Property under financial leases is derecognised if there is reasonable certainty that the Company will transfer its ownership at the end of the lease term.

Leases in which the Company does not transfer a significant part of the risks and rewards incidental to ownership of the underlying asset are classified as operating leases. Revenues from associated leases are recognized in income using the straight-line method over the term of the lease (Note 19.2.2). The corresponding leased assets are included in the Consolidated Statement of Financial Position depending on their nature.

NOTE 5: GROUP STRUCTURE

5.1 Corporate reorganization

On November 6 and 11, 2023, the Boards of Directors of CISA, the Company and GASA, respectively, resolved to instruct their respective managements to analyze a reorganization process under the terms of Section 82 and subsequent sections of the LGS and tax neutrality under Sections 80 and subsequent articles of the Income Tax Law (as amended in 2019), and, if appropriate, draw up the preparatory documentation for the spin-off of CISA's equity and the subsequent merger through absorption of a part of its spun-off equity with Pampa and the other part of its spun-off equity with GASA.

The above-mentioned process, which reorganization effective date is scheduled for January 1, 2024, will derive benefits for the involved companies and for the entire economic group, since it will allow for improved resource efficiency in financial information management and reduced costs for legal and tax advisory fees.

5.2 Acquisition and sale of equity interests

5.2.1 Sale of equity interests of controlling stake in Edenor

On December 28, 2020, the Company entered into with Empresa de Energía del Cono Sur S.A. and Integra Capital S.A., Daniel Eduardo Vila, Mauricio Filiberti and José Luis Manzano (the "Purchaser") a share purchase agreement whereby it agreed to sell its controlling interest in Edenor through the transfer of all Class A shares representing 51% of the capital stock and voting rights of said company (the "Transaction"). On February 17, 2021, Pampa's shareholders meeting was held and the Transaction was approved.

On June 24, 2021, the ENRE approved the Transaction through Resolution No. 207/21, whereas, after meeting the precedent conditions, the transaction closing took place on June 30, 2021, with the transfer of shares and the change of controlling shareholder.

The agreed sales price consisted of: 21,876,856 Class B shares of Edenor, representing 2.41% of Edenor's capital stock and voting rights, transferred upon the execution of the share purchase agreement; and US$ 95 million in cash, which was paid in 3 installments: (i) US$ 5 million upon the execution of the share purchase agreement; (ii) US$ 50 million on the closing date; and US$ 40 million, plus interest at a 10% fixed nominal annual rate (payable quarterly), between June and July 2022.

The results corresponding to the Distribution of energy segment prior to the closing of the transaction were disclosed under "Discontinued operations" of the Consolidated Statement of Comprehensive Income in the fiscal year ended December 31, 2021.

NOTE 5: (Continuation)

The statement of comprehensive income associated with the discontinued operations is disclosed below:

	Distribution of energy
	12.31.2021
Revenue	493
Cost of sales	(398)
Gross profit	95
Selling expenses	(36)
Administrative expenses	(26)
Other operating income	21
Other operating expenses	(18)
Reversal of property, plant and equipment impairment	16
Impairment of financial assets	(11)
Operating income	41
Gain on monetary position, net	120
Financial costs	(106)
Other financial results	8
Financial results, net	22
Profit before income tax	63
Income tax	(138)
Loss of the year from discontinued operations	(75)
Other comprehensive income
Items that will not be reclassified to profit or loss
Exchange differences on translation	34
Items that may be reclassified to profit or loss
Exchange differences on translation (1)	30
Other comprehensive income of the year from discontinued operations	64
Total comprehensive loss of the year from discontinued operations	(11)
Total loss of the year from discontinued operations attributable to:
Owners of the company	(39)
Non - controlling interest	(36)
	(75)
Total comprehensive loss of the year from discontinued operations attributable to:
Owners of the company	(9)
Non - controlling interest	(2)
	(11)

(1)	Corresponds to the reclassification adjustment for exchange differences losses included in profit or loss on Edenor disposal. No exchange differences losses on translation were reconized during 2021.

NOTE 5: (Continuation)

The consolidated statement of cash flows related to discontinued operations as of December 21, 2021 is presented below:

	Distribution of energy
	12.31.2021
Net cash generated by operating activities	116
Net cash used in investing activities	(166)
Net cash used in financing activities	(7)
Decrease in cash and cash equivalents from discontinued operations	(57)
Cash and cash equivalents at the beginning of the year	52
Effect of devaluation and inflation on cash and cash equivalents	5
Decrease in cash and cash equivalents	(57)
Cash and cash equivalents at the end of the year	-

5.2.2 Sale of equity interests in Refinor

On September 15, 2022, the Company entered into an agreement with Hidrocarburos del Norte S.A. for the sale of its Class A shares representing 28.5% of Refinor's capital stock for a price of US$ 5.7 million, subject to the fulfillment of certain precedent conditions.

As of September 30, 2022, in accordance with IFRS 5 and since the transaction price was below the carrying amount, the Company recognised impairment losses, before taxes, for US$ 11 million, which are disclosed under "Share of profit from associates and joint ventures".

On October 14, 2022, once conditions precedent had been met, the Company transferred the above-mentioned shares. Later, the parties entered into an amendment to the agreement stipulating the payment of the price balance as follows: (i) US$ 1.4 million on the amendment's effective date, that is, December 22, 2023; and (ii) US$ 2.6 million in 4 consecutive semi-annual installments of US$ 0.65 million, the first one payable 6 months as from the amendment's effective date.

As of the date of issuance of these Consolidated Financial Statements, the Company has collected US$ 3.1 million, and the amount of US$ 2.6 million is pending collection, to be financed over two years at an annual 8% nominal fixed interest rate in accordance with the terms of the amendment.

NOTE 5: (Continuation)

5.2.3 Acquisition of an additional 50% interest in Greenwind

On August 12, 2022, Vientos Solutions L.L.C., Rio River Capital L.L.C and the Group entered into a share acquisition agreement whereby it acquired, for the amount of US$ 20.5 million, the whole equity interest in VS SLU, a Spanish company which main asset is its 50% interest in Greenwind's capital stock.

On the acquisition date, the Company recorded profits of US$ 23.3 million to reflect the fair value of the 50% stake in Greenwind prior to the aforementioned acquisition, as this transaction is a business combination achieved in stages.

The following table details the fair value of the consideration transferred and the fair values of the assets acquired and the liabilities assumed as of August 12, 2022:

	In millions of US$
Consideration transferred	(20.5)
Fair value of the previous interest in Greenwind	(20.4)
Total	(40.9)
Property, plant and equipment (1)	127.7
Intangible assets - Customer contract (2)	31.6
Financial assets at fair value	24.4
Trade receivables (3)	6.3
Other assets	0.1
Cash and cash equivalents	3.1
Borrowings	(89.3)
Deferred tax liabilities	(54.3)
Income tax liabilities	(4.4)
Trade and other payables	(2.0)
Provisions	(1.4)
Tax liabilities	(0.9)
Total acquisition price allocation (4)	40.9

(1)	Mario Cebreiro Wind Farm's fair value was assessed using the "cost-based approach," which consists of the farm's replacement cost new, adjusted by its loss of value resulting from physical deterioration and functional and economic obsolescence.

(2)

The fair value of this intangible asset regarding the identified business transactions has been determined through the application of the "income-based approach" and the "multi-period excess earnings" method. Key assumptions used considered: i) projected generation level; and ii) discount rate. The useful life was assessed based on the remaining years of the contract.

(3)	For acquired trade receivables, contractual value does not differ from fair value.

(4)	No differences in the acquired assets' accounting valuation were identified, except for the values detailed under Property, plant and equipment and Intangible assets.

NOTE 5: (Continuation)

Expenses related to the acquisition transaction were non-significant, and were recognised as expenses in fiscal year result.

The acquisition contributed to the Group revenues from sales for US$ 11.3 million and net earnings for US$ 3.5 million for the August 12 - December 31, 2022 period.

If the acquisition had taken place on January 1, 2022, the consolidated revenues from sales and the results for the period as of December 31, 2022 would have been US$ 1,844 million and US$ 459 million, respectively. The pro forma information was calculated based on the Company and Greenwind's results.

The Company paid US$ 20.5 million for the acquisition of the additional equity interest which, net of the cash and cash equivalents balance of US$ 3.1 million, results in a net cash flow of US$ 17.4 million, which is disclosed in the consolidated statement of cash flows in the item "Payment for the acquisition of subsidiaries and associates" under investment activities.

5.2.4 Acquisition of Autotrol Renovables S.A.

On September 30, 2022, the Company acquired 100% of the capital stock of Autotrol Renovables S.A., an entity holder of the "Wayra I Wind Farm" project (registered with the National Renewable Energy Projects Registry, "RENPER") for a price of US$ 50 thousand.

5.2.5 Acquisition of VAR

On December 12, 2022, Parque Eólico Arauco S.A.P.E.M. ("PEA") and the Company executed an agreement to acquire 100% of VAR's capital stock. This company is exclusively engaged in electric power generation in the domestic market through the operation of Arauco II Wind Farm, with a 99.75 MW capacity, at a price of US$ 171 million, including the takeover of a US$ 46 million interest liability recorded in VAR and payable by PEA in 12 consecutive monthly installments as from transaction closing.

On December 16, 2022, as the conditions precedent had been met, PEA transferred VAR's shares, and the Company paid US$ 128.1 million, an amount that considers the working capital adjustment estimated on that date. Lastly, in 2023, the final adjustment amounted to US$ 1.8 million in favor of the Company.

The following table details the fair value of the consideration transferred, and the fair values of the assets acquired and liabilities assumed as of, December 16, 2022:

NOTE 5: (Continuation)

	In millions of US$
Consideration transferred	(128.1)
Estimated price adjustment	6.7
Total	(121.4)
Property, plant and equipment (1)	167.7
Intangible assets - Customer contract (2)	62.3
Trade receivables (3)	4.9
Other receivables	1.2
Deferred tax liability	(60.2)
Income tax liability	(5.0)
Trade and other payables	(3.3)
Other payables	(46.0)
Tax liabilities	(0.2)
Total acquisition price allocation (4)	121.4

(1)	Arauco Wind Farm's fair value was assessed using the "cost-based approach," which consists of the farm's replacement cost new, adjusted by its loss of value resulting from physical deterioration and functional and economic obsolescence.

(2)

The fair value of this intangible asset regarding the identified business transactions has been determined through the application of the "income-based approach" and the "multi-period excess earnings" method. Key assumptions used considered: i) projected generation level; and ii) discount rate. The useful life was assessed based on the remaining years of the contract.

(3)	For acquired trade receivables, contractual value does not differ from fair value.

(4)	No differences in the acquired assets' accounting valuation were identified, except for the values detailed under Property, plant and equipment and Intangible assets.

Expenses related to the acquisition transaction were non-significant and they were recognised as expenses in fiscal year result.

If the acquisition had taken place on January 1, 2022, the consolidated revenues from sales and the results for the period as of December 31, 2022 would have been US$ 1,858 million and US$ 448 million, respectively. The pro forma information was calculated based on the Company and VAR's results.

The Company paid US$ 93.2 million for the acquisition of the equity interest, which is disclosed in the consolidated statement of cash flows in the item "Payment for the acquisition of subsidiaries and associates" under investment activities. In addition, the Company made a partial payment by delivering public securities for US$ 34.9 million which is disclosed in the consolidated statement of cash flows in the item "significant non-cash transactions" (see Note 14.3).

5.2.6 Acquisition of additional interest in Rincón de Aranda and divestment in Greenwind

On June 23, 2023, the Company reached an agreement with Total Austral S.A. (Argentine branch) to acquire the additional 45% interest in the Rincón de Aranda block, achieving a 100% interest in the block. As part of the agreement, on the transaction's closing date Pampa transfered 100% of its equity interest in Greenwind, which only asset is the Mario Cebreiro Wind Farm.

Rincón de Aranda is a 240 km2 exploration block located in the oil window of the Vaca Muerta formation, in the Province of Neuquén. It currently has a shut-in production well and an uncompleted well, both drilled in 2019; although the block is not currently in production, its proximity to important productive blocks in the Vaca Muerta formation makes it highly promising from a technical standpoint.

NOTE 5: (Continuation)

On August 16, 2023, after meeting the conditions precedent, including, among others, the assignment approval and the granting of a CENCH over the area to the Company, the transaction was closed.

On its part, Mario Cebreiro Wind Farm, inaugurated in 2018 with a 100 MW capacity and located in Bahía Blanca, Province of Buenos Aires, was the Company's first wind power project, awarded under the Renovar 1 program; it is worth highlighting that, despite the wind farm's assignment, the Company remains committed to renewable energy, which is essential to keep its position as a leading provider of efficient energy, and has started the construction of PEPE VI (see Note 17).

Lastly, with the acquisition of the additional interest in Rincón de Aranda, the Company diversifies its presence in the energy sector with a shale oil block having great production potential and reinforces its commitment to the development of unconventional reserves in Vaca Muerta.

On the closing date, the Company recorded profits of US$ 6.6 million to reflect the fair value of the previously held 55% interest in the Rincón de Aranda block, as well as profits of US$ 0.2 million to reflect the result of the asset swaps.

The fair value of Rincon de Aranda area was based on present value of future net cash flows prepared based on estimates on the future behavior of certain key assumptions, including the following: (i) reference prices for products; (ii) demand projections per type of product; (iii) costs evolution; (iv) macroeconomic variables such as inflation and exchange rates; and (v) the discount rate.

The following table details the value of the transferred consideration and the fair value of assets acquired and liabilities assumed as of August 16, 2023:

	In millions of US$
Assignment of Greenwind's interest net of assumed liabilities (1)	(54.0)
Fair value of Rincón de Aranda's previous interest	(31.6)
Total	(85.6)
Property, plant and equipment (2)	57.0
Inventories (3)	0.9
Tax credits (4)	1.0
Cash and cash equivalents (5)	29.2
Deferred tax liability	(2.3)
Fair value	85.8
Profit	0.2

(1)	The following table details the book value of Greenwind´s interest:

NOTE 5: (Continuation)

	In millions of US$
Property, plant and equipment	121.1
Intangible assets	29.5
Financial assets at fair value through profit and loss	10.9
Trade and other receivables	10.1
Cash and cash equivalents	16.7
Borrowings	(79.7)
Deferred tax liability	(48.3)
Income tax liability	(3.6)
Trade and other payables	(1.1)
Provisions	(0.8)
Tax charges	(0.8)
Assignment of Greenwind's interest net of assumed liabilities	54.0
Provisions assumed by Pampa	(4.2)
Book value of Greenwind´s interest	49.8

The contingency provisions assumed by Pampa correspond to the additional income tax that should have been determined in Greenwind for the fiscal year 2022 without considering the tax loss update regarding the contractual indemnity granted to Total Austral S.A. (Argentine Branch).

(2)

The well's fair value was assessed using the "cost-based approach", which consists of its replacement cost new adjusted by its loss of value resulting from physical deterioration, and functional and economic obsolescence. The fair value of the mining property was assessed using the "income-based approach", considering the development plan contemplated in the concession contract's term.

(3)	The fair value of spare parts was assessed using the "cost-based approach", which consists of the item's replacement cost new adjusted by its loss of value resulting from physical deterioration, and functional and economic obsolescence.

(4)	The contractual value of tax credits does not differ from its fair value.

(5)	Corresponding to the price adjustment paid by Total Austral S.A. (Argentine branch).

As a result of the asset swap, the Company received in cash and cash equivalents the amount of US$ 29.2 million, which, net of the assigned cash and cash equivalents balance of US$ 16.7 million, results in a net cash flow of US$ 12.5 million, disclosed in the statement of cash flows in the item "Collection for equity interests in companies sales" under investment activities.

NOTE 5: (Continuation)

5.3Interest in subsidiaries, associates and joint ventures

5.3.1 Subsidiaries information

Unless otherwise indicated, the country of the registered office is also the principal place where the subsidiary develops its activities.

						12.31.2023		12.31.2022
Company		Country		Main activity		Direct and indirect participation %		Direct and indirect participation %
Autotrol Renovables S.A.		Argentina		Generation		100.00%		100.00%
CISA		Argentina		Trader & investment		100.00%		100.00%
Ecuador Pipeline Holdings Limited		Gran Cayman		Investment		100.00%		-
EISA		Uruguay		Investment		100.00%		100.00%
Enecor S.A.		Argentina		Electricity transportation		70.00%		70.00%
Energía Operaciones ENOPSA S.A. (1)		Ecuador		Oil		-		100.00%
Fideicomiso CIESA		Argentina		Investment		100.00%		100.00%
GASA		Argentina		Generation & Investment		100.00%		100.00%
Greenwind (2)		Argentina		Generation		-		100.00%
HIDISA		Argentina		Generation		61.00%		61.00%
HINISA		Argentina		Generation		52.04%		52.04%
Pampa Ecuador Inc		Nevis		Investment		100.00%		100.00%
PEB		Bolivia		Investment		100.00%		100.00%
PE Energía Ecuador LTD		Gran Cayman		Investment		100.00%		100.00%
PECSA		Chile		Trader		100.00%		-
PESOSA		Argentina		Trader		100.00%		-
Petrolera San Carlos S.A.		Venezuela		Oil		100.00%		100.00%
PB18		Ecuador		Oil		100.00%		100.00%
PISA		Uruguay		Investment		100.00%		100.00%
TGU		Uruguay		Gas transportation		51.00%		51.00%
VAR		Argentina		Generation		100.00%		100.00%
Vientos Solutions Argentina S.A.U.		Argentina		Advisory services		100.00%		100.00%
Vientos Solutions S.L.U.		España		Investment		-		100.00%

(1)	Company merged into PB18.

(2)	See Note 5.2.6.

NOTE 5: (Continuation)

5.3.2 Information about investments in associates and joint ventures

The following table presents the main activity and financial information used for valuation and percentages of participation in associates and joint ventures; unless otherwise indicated, the share capital consists of common shares, each granting the right to one vote:

				Information about the issuer
		Main activity		Date		Share capital		Profit (loss) of the year		Equity		Direct and indirect participation %
Associates
OCP		Investment		12.31.2023		100		17		114		34.08%
TGS (1)		Gas transportation		12.31.2023		1		29		1,058		1.029%
Joint ventures
CIESA (1)		Investment		12.31.2023		1		15		540		50.00%
Citelec (2)		Investment		12.31.2023		1		4		164		50.00%
CTB		Generation		12.31.2023		11		(15)		500		50.00%

(1)	The Company holds a direct and indirect interest of 1.029% in TGS and 50% in CIESA, a company that holds a 51% interest in the share capital of TGS. Therefore, additionally the Company has an indirect participation of 26.50% in TGS.

As of December 31, 2023, the quotation of TGS's ordinary shares and ADR published on the BCBA and the NYSE was $2,956.15 and US$ 15.09, respectively, granting to Pampa (direct and indirect) ownership an approximate stake market value of $ 623,064 million.

(2)

The Company holds a 50% interest in Citelec, a company that holds a 52.65% interest in Transener's capital stock; therefore, the Company has a 26.33% indirect interest in Transener. As of December 31, 2023, Transener's common share price listed at the BCBA was $ 1,210.00, conferring Pampa's indirect interest an approximate $ 141,643 million market value.

NOTE 5: (Continuation)

The details of the balances of investments in associates and joint ventures are as follows:

		12.31.2023		12.31.2022
Disclosed in non-current assets
Associates
OCP		23		15
TGS		14		67
Total associates		37		82
Joint ventures
CIESA		303		435
Citelec		82		117
CTB		250		268
Total joint ventures		635		820
Total associates and joint ventures		672		902

The following tables show the breakdown of the share of profit from associates and joint ventures:

		12.31.2023		12.31.2022		12.31.2021
Associates
Refinor (1)		-		(12)		(2)
OCP		5		(1)		1
TGS		3		7		7
Total associates		8		(6)		6
Joint ventures
CIESA		6		43		50
CTB		(18)		41		49
Citelec		2		3		(3)
Greenwind (2)		-		24		(2)
Total joint ventures		(10)		111		94
Total associates and joint ventures		(2)		105		100

(1)	See Note 5.2.2.

(2)	See Note 5.2.3.

NOTE 5: (Continuation)

The evolution of investments in associates and joint ventures is as follows:

		12.31.2023		12.31.2022		12.31.2021
At the beginning of the year		902		770		547
Dividends		-		(8)		-
Increases		1		1		17
Decrease due to sale of equity interests		(58)		(6)		-
Decrease due to acquisition of control		-		(20)		-
Increase due to acquisition of equity interests		3		-		17
Share of profit		(2)		116		98
(Impairment) Recovery of impairment losses		-		(11)		2
Exchange differences on translation		(174)		60		89
At the end of the year		672		902		770

5.3.3 Investment in CTB

On June 26, 2019, the acquisition by CTB, a company co-controlled by YPF and Pampa, of the goodwill of CTEB, located in the petrochemical complex of Ensenada-Province of Buenos Aires and consisting of two open-cycle gas turbines and an installed capacity of 567 MW, was completed.

CTB undertook to achieve the cycle-closing commissioning, increasing its installed capacity to 847 MW. On January 27, 2023, CTB commissioned the CC, and on February 22, 2023, commercial operations started under the supply contract with CAMMESA. On April 26, 2023, CTB was commissioned to operate with gas oil.

CTB entered into energy supply contracts with CAMMESA under SE Resolution No. 220/07; the open cycle contract terminated on April 27, 2022, and the closed cycle contract is effective for a term of 10 years as from the CC's start of commercial operations. Energy not committed under contracts with CAMMESA is remunerated at the spot market. Finally, CTB entered into an availability and efficiency optimization agreement with CAMMESA for its open-cycle GT units, effective from March 1, 2023 to February 29, 2028, within the framework of SE Resolution No. 59/23 (see Note 2.1.4.4).

In 2019, Pampa and YPF agreed on a management and operation scheme for CTEB whereby the company would be managed by Pampa and YPF Energía Eléctrica S.A. on a rotational basis for 4-year periods. Pampa managed the company during the first period and YPF Energía Eléctrica S.A., on its part, oversaw and managed the works associated with the plant's closing to CC. On December 29, 2023, Pampa and YPF entered into an addendum to the management agreement stipulating a shared management scheme between Pampa and YPF Energía Eléctrica S.A., effective as from January 2024, suspending the previous rotational scheme. The addendum contemplates the possibility of resuming the original rotational scheme at the request of the parties.

NOTE 5: (Continuation)

5.3.3.1 Global Program of CB

On July 23, 2020, CTB's Extraordinary General Shareholders' Meeting resolved to approve the creation of a global program of simple corporate bonds non-convertible into shares for up to US$ 200 million or its equivalent in other currencies or units of value, and the issuance of corporate bonds under such program up to its maximum amount, at any time, to be issued in one or more classes and/or series, which authorization was granted by the CNV on September 24, 2020.

5.3.3.2 Issuance of CB

On June 4, 2021, CTB issued: (i) Class 1 CB for a total amount of US$ 27.3 million, accruing interest at an annual fixed rate of 4% and maturing on June 4, 2023; and (ii) Class 2 CB for a total amount of 37,504,954 units of purchasing power ("UVA"), adjustable by the Reference Stabilization Coefficient (CER), equivalent to $2,928 million, accruing interest at a fixed 4% rate and maturing on June 4, 2024.

On August 18, 2021, CTB reopened (i) Class 1 CB for a total amount of US$ 15.6 million at an issue price of 101.7050%; and (ii) Class 2 CB for a total amount of 27.9 million UVA at an initial value of $84.76 per UVA at an issue price of 100.82%.

On November 26, 2021, CTB issued Class 4 CB for a total amount of US$ 96 million, accruing interest at an annual 0% fixed rate and maturing on November 26, 2024.

On May 16, 2022, CTB issued: (i) Class 6 CB for a total amount of US$ 25 million at a fixed annual 0% rate maturing on May 16, 2025; and (ii) Class 7 CB for a total amount of $ 1,754 million accruing interest at a variable Badlar rate plus an annual 2.98% spread and maturing on November 16, 2023, date in which were totally cancelled.

On August 22, 2022, CTB issued Class 8 CB for a total amount of $ 4,235 million, accruing interest at a variable Badlar rate plus a 1.00% annual spread and maturing on February 22, 2024.

Finally, on December 12, 2022, CTB reopened additional Class 6 CB for a total amount of US$ 58.6 million accruing interest at an annual 0% fixed rate and maturing on May 16, 2025. With the reopening of Class 6 CB, which were subscribed and paid in cash and in-kind through the delivery of Class 1 CB, Class 1 CB with a fair value of US$ 10.7 million were partially canceled.

It is worth highlighting that the resolutive condition of the guarantees granted by CTB's co-controlling shareholders (Pampa and YPF) to holders of outstanding Classes 1, 2, 4, 6, 7 and 8 CB issued by CTB to secure the timely and proper payment of any owed amount, including principal and interest services, was fulfilled with the CC's commissioning on February 22, 2023. Consequently, these guarantees were terminated and rendered ineffective and unenforceable.

NOTE 5: (Continuation)

On April 3, 2023, CTB issued Class 9 CB for a total amount of US$ 50 million at an annual 0% fixed Badlar rate maturing on April 3, 2026. These CB were subscribed and paid in cash and in kind through the delivery of the Class 1 CB; therefore, Class 1 CB for a face value of US$ 2.2 million were partially canceled. The remaining outstanding face value of Class I CB, amounting to US$ 30 million, was redeemed in full in May 2023.

As of the date of issuance of these Consolidated Financial Statements, CTB is in compliance with all the covenants established in its debt agreements.

Additionally, CTB took out import financing for US$ 0.8 million.

Post-closing, the Company took out short-term bank loans in pesos for $ 31,786 million at an average annual 106% interest rate and, in January 2024, it early redeemed all Class 2 CB.

5.3.3.3 Impairment of non-financial assets

As of December 31, 2023, CTB did not identify indications that could impact the assumptions considered in the recoverability assessment performed as of December 31, 2022. It should be noted that CTB has not recorded any impairment losses as a result of aforementioned assessment.

5.3.4 Investment in OCP

The Company, through PEB, has an equity stake in OCP, which in turn holds the whole capital stock and voting rights of OCP SA, the licensee company of an oil pipeline in Ecuador with a transportation capacity of 450,000 barrels/day.

On August 12, 2021, the Company, through its subsidiary PEB, entered into an agreement with Occidental International Exploration and Production Company for the acquisition of all the shares of Occidental del Ecuador Inc. (currently Pampa Ecuador Inc.), a company which in turn holds shares representing 14.15% of OCP's capital stock, for US$ 5 million.

On its part, on November 30, 2023, the Company, through its subsidiary PEB, entered into an agreement with Burlington Resources Oriente Limited and Perenco S.A for the purchase of Ecuador Pipeline Holdings Limited, a company which in turn holds shares representing 4% of OCP's capital stock, in consideration of a price equivalent to US$ 1 (one dollar).

NOTE 5: (Continuation)

The closing of these transactions, taking into consideration the timing of the agreements and the concession's extension term, involved the recognition of profits for US$ 17.2 million and US$ 3.7 million under IAS 28. The following table details the consideration and the fair values of the assets acquired and the profits recorded on the detailed acquisition dates:

	8.12.21	11.30.23
	In millions of US$
Acquisition cost	(5.0)	-
Total consideration	(5.0)	-
Share value of the interest in the fair value of OCP's identifiable assets and liabilities (1)	12.7	2.4
OCP dividends to be received	9.5	-
Cash and cash equivalents	-	1.3
Assets fair value	22.2	3.7
Profit (2)	17.2	3.7

(1)	Calculated based on the present value of expected dividend flows.

(2)	Disclosed under "Share of profit from associates and joint ventures".

On August 12, 2021, PEB recorded an impairment reversal of US$ 1.6 million, on the interest in OCP, prior the aforementioned acquisition, in relation to the estimation of the present value of the future cash flows that were expected to be obtained through the collection of dividends considering the concession term and a discount rate of 15.09%.

Additionally, on May 4, 2023, the Company, through its subsidiary PEB, entered into a purchase agreement with Repsol OCP de Ecuador S.A. to acquire 2,979,606,613 additional shares, representing 29.66% of OCP, for a price of US$ 15 million, adjusted by subtracting the dividends collected by Repsol OCP de Ecuador S.A. between January 1, 2023 and the transaction closing date. As of December 31, 2023, the closing of the transaction was subject to the customary conditions precedent for this kind of transactions, including the applicable governmental approvals.

Post-closing, on January 16, 2024, the transaction was closed. It is worth highlighting that with this transaction the Company, through PEB, reaches a 63.74% equity interest in OCP's capital stock and obtains joint control, in accordance to the commitment to amend the shareholders' agreement dated on January 9, 2024 with PetroOriental OCP Holdings Ltd.

5.3.4.1 Concession termination

Given the Government's interest in ensuring continuity in the provision of the public hydrocarbon transportation utility through the heavy crude oil pipeline, on January 19, 2024 the Ministry of Energy and Mines of Ecuador and OCP SA agreed to extend its term until July 31, 2024 to: (i) allow the Government the time necessary to verify compliance with the authorization contract, including the pipeline's original diameter in all its sections, the enabling licenses issued by the Energy and Non-Renewable Natural Resources Regulation and Control Agency, and (ii) allow OCP SA to substantiate compliance with the authorization contract. The parties will also review the objectives set for the transition process, agree on the content of the termination agreement, and take the necessary measures for the transfer of the company.

NOTE 5: (Continuation)

5.3.4.2 Dividend distribution and share buyback

Post-closing, on January 5, on January 18, 2024, OCP declared dividends for US$13.3 million. Additionally, on January 22, 2024, OCP repurchased a total of 5,740,902,124 own ordinary shares for a US$ 0.01 price each.

As a consequence of the aforementioned, on January 22, 2024, the Company, through PEB, received US$ 8.5 million for dividend distribution and US$ 36.6 million for stock buyback, in relation to its 63.74% interest in OCP.

5.3.4.3 Contingent liabilities in OCP SA

During 2023, upon the occurrence of a force majeure event related to the erosive process in the Quijos River bed, in the San Rafael sector, on the border of the provinces of Sucumbíos and Napo, Ecuador, several organizations and individuals filed a constitutional protection action against OCP SA, as well as against the Ministry of Energy, the Ministry of Environment and Water, Petroecuador and the Ministry of Health, alleging violation of several constitutional rights. The safeguard action was dismissed in the second instance by Orellana's Provincial Court of Justice; however, the plaintiffs filed a constitutional protection action, which was upheld by the Constitutional Court.

In 2023, due to the Force Majeure event resulting from the pipeline rupture in 2020 mentioned in the previous paragraph, the decentralized autonomous government of Orellana filed a constitutional protection action against OCP SA and Petroecuador alleging violation of several constitutional rights. The protection action has not been resolved as of the date of issuance of these Financial Statements.

Moreover, in 2023, due to the Force Majeure event resulting from the pipeline rupture in 2020, residents of the Puerto Madero area filed a constitutional protection action against OCP SA, the Presidency of the Republic of Ecuador and EP Petroecuador alleging violation of several constitutional rights. The protection action has not been resolved as of the date of issuance of these Financial Statements. OCP SA's management, jointly with its legal advisors, has determined that the probability of an adverse ruling is remote.

5.3.5 Investment in CITELEC

5.3.5.1 Impairment in the value of non-financial assets in Transener

The projections used by Transener in the calculation of the recoverable amount of long-lived non-financial assets considered 3 weighted alternatives associated with: (i) the status of negotiations with the ENRE; (ii) the Right-of-Use and Associated Maintenance contract; (iii) Transener's management expectations on the transitional tariff increase to be granted until the conclusion of the new RTI; (iv) Transener's expectations on the timeliness and outcome of the new RTI process; and (v) the impact of a cost monitoring scheme allowing for bi-annual updates to current tariffs.

As of December 31, 2023 and 2022, the book value of Transener's long-lived non-financial assets does not exceed their recoverable amount.

5.3.5.2 Distribution of earnings

Regarding the loan agreement executed in July 2021 between Transener and BNA in the amount of $ 1,000 million, for the tree-year term, Transener's Board of Directors has committed, while the loan remains outstanding, to refrain from making any proposal to the Shareholders' Meeting regarding the release of reserves for their distribution as dividends to shareholders or, in case there are negative results affecting reserves, from proposing the distribution of earnings until reserves have been replenished.

NOTE 5: (Continuation)

5.3.6 Investment in CIESA

Impairment of non-financial assets in TGS

Argentina's main macroeconomic and business variables have deteriorated since August 2019. This situation worsened in 2020 due to the negative consequences of the COVID pandemic on the Argentine economic situation, which forced the Argentine Government to take a series of measures, even affecting the regulatory framework of the natural gas transportation segment. As a result, TGS has re-estimated the cash flows used in determining the recoverable value (value in use) of the CGU in the Natural Gas Transportation segment.

The projections used in the calculation of the recoverable amount considered 3 weighted alternatives associated with: (i) the status of negotiations with the Argentine Government; (ii) the contractual rights resulting from the license; (iii) expectations on the transitional tariff increase to be granted until the conclusion of the new RTI; (iv) expectations on the result of the new RTI process; and (v) the impact of a cost monitoring scheme allowing for bi-annual updates to current tariffs.

As of December 31, 2023 and 2022, TGS has determined that it is not necessary to record an additional impairment charge, nor to reverse the recorded one.

5.4 Operations in oil and gas consortiums

5.4.1 General considerations

The Company is jointly and severally liable with the other participants for meeting the contractual obligations under these arrangements.

The production areas in Argentina are operated pursuant to concession production agreements with free hydrocarbons availability.

For the computable crude oil and natural gas in Argentina production, according to Law No.17,319, are paid royalties equivalent to 12% of the wellhead price of crude oil and natural gas. The wellhead price is calculated by deducting freight and other sales related expenses from the sale prices obtained from transactions with third parties. This rate may increase from 3% to 4% depending on the producing jurisdiction and market value of the product.

NOTE 5: (Continuation)

5.4.2 Oil and gas participation details

As of December 31, 2023, the Company and its associates are part of the joint operations and consortia for the exploration and production of oil and gas as indicated below:

					Participation				Duration Up To
Name			Location		Direct		Operator
Argentine production
Río Neuquén			Río Negro and Neuquén		31.42% and 33.07%		YPF		2027/2051
Sierra Chata			Neuquén		45.55%		PAMPA		2053
El Mangrullo			Neuquén		100.00%		PAMPA		2053
La Tapera - Puesto Quiroga			Chubut		35.67%		Tecpetrol		2027
El Tordillo			Chubut		35.67%		Tecpetrol		2027
Aguaragüe (1)			Salta		15.00%		Tecpetrol		2037
Gobernador Ayala			Mendoza		22.51%		Pluspetrol		2036
Río Limay este (Ex Senillosa) (2)			Neuquén		85.00%		PAMPA		2040
Rincón de Aranda (3)			Neuquén		100.00%		PAMPA		2058
Veta Escondida			Neuquén		55.00%		PAMPA		2027
Rincón del Mangrullo			Neuquén		50.00%		YPF		2052
Los Blancos (ex Chirete)			Salta		50.00%		High Luck Group Limited		2045
Argentine exploration
Parva Negra Este (4)			Neuquén		85.00%		PAMPA		2025
Río Atuel (5)			Mendoza		33.33%		Petrolera El Trebol		2023
Borde del Limay (6)			Neuquén		85.00%		PAMPA		2015
Los Vértices (6)			Neuquén		85.00%		PAMPA		2015
Las Tacanas Norte (7)			Neuquén		90.00%		PAMPA		2027

(1)

On February 3, 2023, an agreement for a 10-year extension of the concession was signed with the enforcement authority. The agreement includes investment commitments for the execution of 1 well, 2 workovers and 2D seismic reprocessing, and was ratified by Provincial Executive Order No. 543/23 published on August 14, 2023 in Salta's BO.

(2)	On January 2, 2023, the environmental remediation plan was approved by the Province of Neuquén's Undersecretariat of Environment, a necessary preliminary step to relinquish the block.

(3)	On June 23, 2023 the additional 45% interest in the block was acquired (see details below).

(4)	On December 5, 2023, the addendum to the block's Joint Venture agreement was approved (see details below).

(5)

On July 10, 2023, the Company and Petrolera El Trébol informed the Ministry of Economy and Energy of the Province of Mendoza of their decision to fully relinquish the block classified as a lot under evaluation pursuant to section 81 (b) of Act No. 17,319. Consequently, the Company has written off exploration wells for US$ 6.6 million.

(6)	Under process of relinquishment to the province.

(7)	On November 30, 2023, the addendum to the exploration, development and production agreement for the block was approved (see details below).

NOTE 5: (Continuation)

The assets and liabilities as of December 31, 2023 and 2022 and the production cost of Joint Ventures and Consortiums in which the Company has interests for the years ended on those dates are detailed below:

		12.31.2023		12.31.2022
Non-current assets		112		227
Current assets		7		16
Total assets		119		243
Non-current Liabilities		17		25
Current Liabilities		29		53
Total liabilities		46		78
Production cost		94		85

It is worth highlighting that the information presented does not include charges recorded by the Company as a member of the Joint Ventures and Consortiums.

Assignment of mixed companies in Venezuela

On May 6, 2022, the Company transferred to Integra Petróleo y Gas S.A. (the "Assignee") all the rights and obligations of the Company for its direct and indirect interest in the capital of the following mixed companies in the Bolivarian Republic of Venezuela: Petroritupano S.A., Petroven-Bras S.A., Petrowayú S.A. and Petrokariña S.A. (the "Mixed Companies") that exploit four hydrocarbon production areas in that country: Oritupano Leona, La Concepción, Acema and Mata (the "Areas"). As consideration for the assignment, the Assignee will pay to the Company 50% of any payment it obtains, whether monetary or in kind (including, without limitation, an indemnity, compensation, reparation or similar) related to the direct or indirect interest in the Mixed Companies and the Areas. This transaction is subject to the change of control approval by the Minister of Popular Power of Petroleum of the Bolivarian Republic of Venezuela.

As of the date of issuance of these Consolidated Financial Statements, the Company considers contingent the collection right associated with the assignment, in terms of IAS 37, taking into consideration that it is subject to the change of control approval and subsequent collection of payments by the Assignee.

Anticlinal Campamento termination agreement

On January 19, 2023, the Company accepted Oilstone Energía S.A.'s offer to terminate its rights and obligations under the investment agreement, the Joint Operation and the operating agreement of the block, effective from January 1, 2023.

Estación Fernández Oro termination agreement

On March 14, 2023, the Company accepted YPF S.A.'s proposal to terminate, effective as from January 1, 2023, all the Company's rights and obligations in the investment agreement, the Joint Operation and the operating agreement for the Estación Fernández Oro block's exploitation concession.

Acquisition of additional interest and grant of CENCH at Rincón de Aranda

On June 23, 2023, the Company executed an agreement with Total Austral S.A. (Argentine branch) to acquire the additional 45% interest in the Rincón de Aranda area. As part of the agreement, on the transaction's closing date, the Company assigned 100% of its equity interest in Greenwind, which only asset is the Mario Cebreiro Wind Farm (see Note 5.2.6).

NOTE 5: (Continuation)

On July 26, 2023, the Company entered into a Memorandum of Understanding with the Province of Neuquén agreeing on the CENCH granting terms. Later, pursuant to Executive Order No. 1,435/23, the Province of Neuquén approved the above-mentioned Memorandum of Understanding and the assignment of Total Austral S.A. (Argentine branch)'s interest to the Company, and granted the CENCH in favor of the Company. The assignment of rights over the block and the CENCH are effective as from August 16, 2023, the transaction's closing date.

The Company had a 55% interest in the block; therefore, after the closing of the transaction, it reached a 100% interest in Rincón de Aranda.

As part of the CENCH's granting, the Company committed to carry out a pilot program involving the completion of 1 previously drilled well, as well as the drilling and completion of 2 pads consisting of 8 wells, and the construction and adaptation of surface facilities, with an estimated US$ 161 million investment.

Exploration, Development and Production Agreement, Las Tacanas North Block

On November 30, 2023, Executive Order No. 2,426/23 was published, approving the Exploration, Development and Production Agreement for the Las Tacanas Norte block entered into between the Company and Gas y Petróleo del Neuquén S.A. on November 24, 2023, under the Neuquén Exploratory Plan, whereby the Company receives a 90% interest in the Las Tacanas Norte block for a 4-year exploratory period, to be operated by the Company and with the commitment to carry out certain exploration tasks of hydrocarbon potential, including the execution of one vertical exploratory well, scheduled for the first four-month period of the third year of the exploratory period.

Continuity plan in the Parva Negra Este block

On December 5, 2023, Executive Order No. 2,498/23 was published, approving Addendum II to the Joint Venture Agreement for the Parva Negra Este block, whereby ExxonMobil Exploration Argentina S.R.L assigns to the Company its 42.50% interest in the Joint Venture.

It also approves the relinquishment of 50% of the block, a surface of 143 km2 therefore corresponding to the Concession. In turn, it approves the Lot Under Evaluation for the 3-year period from April 3, 2022 to April 2, 2025, including the commitment to execute 1 horizontal well targeting the Vaca Muerta formation, with an associated investment of US$ 16 million, to be executed before September 30, 2024.

NOTE 5: (Continuation)

5.5 Exploratory well costs

The following table provides the year end balances and activity for exploratory well costs, during the years ended December 31, 2023, 2022 and 2021:

		12.31.2023		12.31.2022		12.31.2021
At the beginning of the year		37		42		50
Increases		2		2		8
Transferred to development		-		(7)		(16)
Derecognition of unproductive wells		(7)		-		-
At the end of the year		32		37		42
Number of wells at the end of the year		4		7		10

NOTE 6: RISKS

6.1 Critical accounting estimates and judgments

The preparation of financial statements requires the Company's Management to make future estimates and assessments, to apply critical judgment and to establish assumptions affecting the application of accounting policies and the amounts of disclosed assets and liabilities, income and expenses.

The applied estimates and accounting judgments are evaluated on a continuous basis and are based on past experiences and other reasonable factors under the existing circumstances. Actual future results might differ from the estimates and evaluations made at the date of preparation of these Consolidated Financial Statements. The estimates which have a significant risk of producing adjustments on the amounts of the assets and liabilities during the following year are detailed below:

6.1.1 Impairment of non-financial long-lived assets

Non-financial long-lived assets, including identifiable intangible assets and right-of-use assets, are reviewed for impairment at the lowest level for which there are separately identifiable cash flows (CGU). For this purpose, each assets group with independent cash flows, each subsidiary, associate and each jointly controlled company has been considered a single CGU, as all of their assets jointly contribute to the generation of cash inflows, which are derived from a single service or product; thus cash inflows cannot be attributed to individual assets.

NOTE 6: (Continuation)

In order to evaluate if there is evidence that a CGU could be affected, both external and internal sources of information are analyzed. Specific facts and circumstances are considered, which generally include the discount rate used in the estimates of the future cash flows of each CGU and the business condition as regards economic and market factors, such as the cost of inventories, oil and gas prices, international petrochemical product's price, the regulatory framework for the energy industry, the projected capital investments and the evolution of the energy demand.

The value in use of each CGU is estimated on the basis of the present value of future net cash flows expected to be derived on the UGE. Management uses approved budgets up to one year as the base for cash flow projections that are later extrapolated into a term consistent with the assets' remaining useful life, taking into consideration the appropriate discount rates. The discount rates used to discount future net cash flows is the WACC, for each CGU a specific WACC was determined which considered the business segment and the country conditions where the operations are performed. In order to calculate the fair value less the costs of disposal, the Company Management uses the estimated value of the future cash flows that a market participant could generate from the appropriate CGU, less the necessary costs to carry out the sale of the corresponding CGU.

The Company Management is required to make judgments at the moment of the future cash flow estimation. The actual cash flows and the values may differ significantly from the expected future cash flows and the related values obtained through discount techniques.

6.1.2 Current and deferred Income tax

The Company's Management periodically evaluates tax treatments affecting the determination of taxable profit regarding uncertain tax treatment under tax law considering the acceptability of a particular tax treatment by the relevant taxation authority, and, if applicable, recognizes tax provisions to reflect the effect of the uncertainty for each tax treatment based on the amount estimated to be paid to the tax authorities.

If the final tax resolution regarding uncertain tax treatments differs from recognised figures, such differences will have an effect on income tax and deferred income tax at the year of such determination.

Deferred tax asset is reviewed at each reporting date and reduced in accordance with the probability that the sufficient taxable base will be available to allow and for the total or partial recovery of these assets. In assessing the recoverability of deferred tax assets, Management considers if it is likely that a portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets depends on the generation of future taxable income in the periods in which these temporary differences become deductible. To make this assessment, Management takes into consideration the scheduled reversal of deferred tax liabilities, the projections of future taxable income and tax planning strategies.

The generation of future taxable profits may differ from these estimated affecting the deductibility of deferred tax assets.

NOTE 6: (Continuation)

6.1.3 Provision for contingencies

The Company is subject to various claims, lawsuits and other legal proceedings that arise during the ordinary course of its business. The Company's liabilities with respect to such claims, lawsuits and other legal proceedings cannot be estimated with certainty. The Company reviews the status of each contingency and assesses potential financial liability, applying the criteria indicated in Note 4.21, for which elaborates the estimates mainly with the assistance of legal advisors, based on information available to the Management at Consolidated Financial Statements date, and taking into account the litigation and resolution/settlement strategies.

Contingencies include outstanding lawsuits or claims for possible damages to third parties in the ordinary course of the Company's business, as well as third party claims arising from disputes concerning the interpretation of legislation.

The Company evaluates whether there would be additional expenses directly associated with the ultimate resolution of each contingency, which will be included in the provision if they may be reasonably estimated.

The final resolutions of the litigation could differ from Management's estimates, generating current provisions to be inadequate, which could have a material adverse effect on the statement of financial position, comprehensive income, changes in equity and cash flows.

6.1.4 Asset retirement obligations and decommissioning of wind turbines

Asset retirement obligations in oil and gas areas after completion of operations require the Company's Management to estimate the number of wells, long-term well abandonment costs and the time remaining until abandonment.

In the same way, the obligations related to the decommissioning of wind turbines in wind farms require the Company's Management to estimate long-term dismantling costs and the time remaining until the dismantling.

Technology, costs and political, environmental and safety considerations constantly change and may result in differences between actual future costs and estimates.

Asset retirement obligations' and the decommissioning of wind turbines' estimates are adjusted at least once a year or more frequently if there are changes in the assumptions considered in the assessment.

NOTE 6: (Continuation)

6.1.5 Impairment of financial assets and other credits

The Group is exposed to losses for uncollectible receivables. The Company Management estimates the final collectability of the accounts receivable.

The accounting of expected credit losses for trade receivables and other receivables with similar risk characteristics is based on the Company's best estimate of the default risk and the calculation of the expected credit losses rates, based on historical information of the behavior of the Company's clients, current market conditions and forward-looking estimates at the end of each reporting period.

In order to estimate collections related to the sale of gas and energy in the spot market and revenues associated with natural gas production promotion plans, the Company mainly considers CAMMESA's and federal government's capacity to meet its payment obligations to generators and producers, including the resolutions issued by the SE, which allow the Company to collect its receivables through different mechanisms.

Future adjustments to the allowance may be necessary if future real economic conditions differ substantially from the assumptions used in the assessment for each year.

6.1.6 Actuarial assumptions in defined benefit plans

Commitments with defined benefit plans to employees are recognised as liabilities in the statement of financial position based on actuarial estimates revised annually by an independent actuary, using the projected unit credit method.

The present value of defined benefit pension plan depends on multiple factors that are determined according to actuarial estimates, net of the fair value of the plan assets, when applicable. For this purpose, certain assumptions are used including the discount rate and wage growth rate assumptions. It may be necessary to make adjustments in the future if future real economic conditions materially differ from the assumptions used in the valuation of each year.

6.1.7 Oil and gas reserves

Reserves include oil and gas volumes (in m3 of oil equivalent) that are economically producible, in the areas where the Company operates or has a direct or an indirect interest and over which the Company has exploration and exploitation rights.

There are numerous uncertainties in estimating proved and unproved reserves, future production profiles, development costs and prices, including several factors beyond the producer's control. Reserve engineering is a subjective process of estimating underground accumulations involving a certain degree of uncertainty.

NOTE 6: (Continuation)

Reserves estimates depend on the quality of the available engineering and geological data as of the estimation date and on the interpretation and judgment thereof.

Periodic revisions and adjustments to the estimated oil and gas reserves and related future net cash flows may be necessary as a result of changes in a number of factors, related to reservoir performance, new drilling, oil and gas prices, cost, technological advances, new geological or geophysical data, and other economic factors or at least once a year.

The Company's estimates of oil and gas reserves have been developed by the Company's internal specialists, specifically petroleum engineers, and audited by independent specialists engaged by Company.

The Company uses the information obtained from the calculation of reserves in the determination of depreciation of properties, plant and equipment used in oil and gas areas, as well as assessing the recoverability of these assets and including, when applicable, goodwill allocated to the oil and gas segment (see Notes 4.6 to 4.9).

6.1.8 Environmental remediation

The costs incurred to limit, neutralize or prevent environmental pollution are only capitalized if at least one of the following conditions is met: (a) such costs relate to improvements in safety; (b) the risk of environmental pollution is prevented or limited; or (c) the costs are incurred to prepare the assets for sale and the book value of such assets does not exceed their respective recoverable value.

Liabilities related to future remediation costs are recorded when, on the basis of environmental assessments, such liabilities are probable to materialize, and costs can be reasonably estimated. The actual recognition and amount of these provisions are generally based on the Company's commitment to an action plan, such as an approved remediation plan or the sale or disposal of an asset. In general, the provision is recognised on the basis that a future remediation commitment may be required.

The Company measures liabilities based on its best estimation of present value of future costs, using currently available technology and applying current environmental laws and regulations as well as the Company's own internal environmental policies.

NOTE 6: (Continuation)

6.1.9 Fair value of financial assets that are not traded in active markets

The fair value of financial instruments that are not traded in active markets is determined using valuation techniques. These valuation techniques consider estimates based on information available to the Management at Consolidated Financial Statements date, for those significant variables that cannot be observed in the market, including the discount rate, among others.

Future adjustments may be necessary if future real economic conditions differ substantially from the assumptions used in the valuation for each period.

6.1.10 Business Combinations

The acquisition method involves the measurement at fair value of the identifiable assets acquired and the liabilities assumed in the business combination at the acquisition date.

For the purpose to determine the fair value of identifiable assets, the Company uses the valuation approach considered the most representative for each asset. These include: i) the income approach, through indirect cash flows (net present value of expected future cash flows) or through the multi-period excess earnings method, ii) the cost approach (replacement value of the good adjusted for loss due to physical deterioration, functional and economic obsolescence) and iii) the market approach through comparable transactions method.

Likewise, in order to determine the fair value of liabilities assumed, the Company's Management considers the probability of cash outflows that will be required for each contingency, and elaborates the estimates with assistance of legal advisors, based on the information available and taking into account the strategy of litigation and resolution / liquidation.

Management critical judgment is required in selecting the approach to be used and estimating future cash flows. Actual cash flows and values may differ significantly from the expected future cash flows and related values obtained through the mentioned valuation techniques.

6.2Financial risk management

6.2.1 Financial Risk Factors

The Company's activities are subject to several financial risks: market risk (including the exchange rate risk, the interest rate risk and the price risk), credit risk and liquidity risk.

NOTE 6: (Continuation)

Financial risk management is encompassed within the Company's global policies, there is an integrated risk management methodology, where the focus is not placed on the individual risks of the business units' operations, but there is rather a wider perspective focused on monitoring risks affecting the whole portfolio. The Company's risk management strategy seeks to achieve a balance between profitability targets and risk exposure levels. Financial risks are those derived from financial instruments the Company is exposed to during or at the closing of each fiscal year. The Company uses derivative instruments to hedge certain risks when it deems it necessary according to its risk management internal policies.

Financial risk management is controlled by the Financial Department, which identifies, evaluates and covers financial risks. Risk management systems and policies are reviewed on a regular basis to reflect changes in market conditions and the Company's activities, and have been applied consistently during the periods included in these Consolidated Financial Statements. This section includes a description of the main risks and uncertainties which may adversely affect the Company's strategy, performance, operational results and financial position.

6.2.1.1 Market risks

6.2.1.1.1 Foreign exchange risk

The Company's results of operations and financial position are exposed to changes in the exchange rate between the Company's functional currency, which is the U.S. dollar and other currencies, primarily with respect to the Argentine peso (which is the legal currency in Argentina). In some cases, the Company may use derivative financial instruments to mitigate the associated exchange rate risk.In fiscal year 2023, the U.S. dollar recorded an approximate 356.3 % increase against the Argentine peso, from $ 177.16 in December 2022 to $ 808.45 in December 2023, and taking into consideration that during the year the Company mostly had a net passive position in Argentine pesos, as of December 31, 2023 the Company recorded net foreign exchange gain in the amount of US$ 123 million. Taking into account the net active financial position in Argentine pesos as of December 31, 2023, the Company estimates that provided all other variables remain constant, a 10% revaluation/(devaluation) of U.S. dollar as compared to the Argentine peso would generate in absolute values a (decrease)/increase of US$ 6 million in the 2023 fiscal year's income, before income tax.

The Group´s exposure to other foreign currency movements is not material.

NOTE 6: (Continuation)

6.2.1.1.2 Price risk

The Company's financial instruments are not significantly exposed to hydrocarbon international price risks because the current regulatory, economic and governmental policies in force, prevent oil and gas domestic prices to be directly affected in the short-term due to variations in the international market.

Additionally, the Company's investments in financial assets classified as "at fair value through profit or loss" are sensitive to the risk of changes in the market prices resulting from uncertainties as to the future value of such financial assets.

The Company estimates that provided all other variables remain constant, a 10% revaluation/(devaluation) of each market price would generate the following increase/(decrease) in the fiscal year's income, before income tax in relation to financial assets at fair value through profit and loss detailed in Note 12.2 to these Consolidated Financial Statements:

			Increase of the result for the year
Financial assets			12.31.2023		12.31.2022
Shares			12		19
Government securities			39		28
Corporate Bonds			8		12
Mutual funds			-		3
Variation of the result of the year			59		62

6.2.1.1.3 Cash flow and fair value interest rate risk

The management of the interest rate risk seeks to reduce financial costs and limit the Company's exposure to interest rate increases.

Indebtedness at variable rates exposes the Company to the interest rate risk on its cash flows due to the possible volatility they may experience. Indebtedness at fixed rates exposes the Company to the interest rate risk on the fair value of its liabilities, since they may be considerably higher than variable rates.

As of December 31, 2023, 5% of the indebtedness was subject to variable interest rates. Furthermore, 58% of the Company's debt accruing variable interest rates is denominated in U.S. dollars, mainly at SOFR rate plus an applicable spread. It should be pointed out that there has been no material impact on behalf of the replacement of the LIBOR reference interest rate effective by the SOFR rate, as from July 2023, on the Company's indebtedness subject to the mentioned reference rate.

NOTE 6: (Continuation)

The Company seeks to mitigate its interest-rate risk exposure through the analysis and evaluation of: (i) the different liquidity sources available in the financial and capital market, both domestic and (if available) international; (ii) interest rates alternatives (fixed or variable), currencies and terms available for companies in a similar sector, industry and risk than the Company; (iii) the availability, access and cost of interest-rate hedge agreements. On doing this, the Company evaluates the impact on profits or losses resulting from each strategy over the obligations representing the main interest-bearing positions.

In the case of fixed rates and in view of the market's current conditions, the Company considers that the risk of a significant decrease in interest rates is low and, therefore, does not foresee a substantial risk in its indebtedness at fixed rates.

As of the date of issuance of these Consolidated Financial Statements, the Company is not exposed to a significant risk of variable interest rate increases since the 95% of the financial debt is subject to fixed rate.

The following table shows the breakdown of the Company's borrowings classified by interest rate and the currency in which they are denominated:

			12.31.2023		12.31.2022
Fixed interest rate:
Argentine pesos			33		57
U.S. dollar			1,210		1,173
Yuan R.China			5		-
Subtotal loans obtained at a fixed interest rate			1,248		1,230
Floating interest rate:
Argentine pesos			30		140
U.S. dollar			41		149
Subtotal loans obtained at a floating interest rate			71		289
Non interest accrued:
Argentine pesos			11		22
U.S. dollar			118		72
Subtotal loans no interest accrued			129		94
Total borrowings			1,448		1,613

Based on the conducted simulations, and provided all other variables remain constant, a 10% increase/decrease in variable interest rates would generate the following (decrease)/increase in the 2023 fiscal year's income, before income tax, of US$ 4 million.

NOTE 6: (Continuation)

6.2.1.2 Credit risk

The Company establishes individual credit limits according to the limits defined by the Board of Directors and approved by the Financial Department based on internal or external ratings. The Company makes constant credit assessments on its customers' financial capacity, which minimizes the potential risk for bad debt losses.

The credit risk represents the exposure to possible losses resulting from the breach by commercial or financial counterparties of their obligations taken on with the Company. This risk stems mainly from economic and financial factors or a possible counterparty default.

The credit risk is associated with the Company's commercial activity through customer trade receivables, as well as available funds and deposits in banking and financial institutions.

The Company, in its ordinary course of business and in accordance with its credit policies, grants credits to a large customer base, mainly large sectors of the industry, including petrochemical companies, natural gas distributors and electricity large users.

As of December 31, 2023, the Company's trade receivables totaled US$ 209 million and is classified as current. With the exception of CAMMESA, which represents approximately 48% of such trade receivables, the Company does not have a significant credit risk concentration, as this exposure is distributed among a large number of customers and other counterparties.

The impossibility by CAMMESA to pay these receivables may have a substantially adverse effect on cash income and, consequently, on the result of operations and financial situation which, in turn, may adversely affect the Company's repayment capacity.

The credit risk of liquid funds and other financial investments is limited since the counterparties are high credit quality banking institutions. If there are no independent risk ratings, the Financial Department evaluates the customer's creditworthiness, based on past experiences and other factors.

The Company applies the simplified approach of IFRS 9 to measure the expected credit losses of trade receivables and other receivables in accordance with the policy described in Note 4.10.4.

NOTE 6: (Continuation)

The expected credit loss on financial assets and trade receivables amounted to US$ 1 million as of December 31, 2023, 2022 and 2021 and was determined based on credit loss rates calculated for days past due detailed below:

12.31.2023	Undue	30 days	60 days	90 days	120 days	150 days	180 days	+ 180 days
Generation	0.32%	1.26%	8.33%	16.63%	20.72%	23.46%	27.00%	28.96%
Oil and Gas	0.06%	0.30%	2.19%	3.83%	5.06%	10.14%	10.14%	10.21%
Petrochemicals	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%	28.96%
Holding	0.18%	1.04%	8.44%	9.09%	9.09%	9.09%	9.09%	9.09%
12.31.2022	Undue	30 days	60 days	90 days	120 days	150 days	180 days	+ 180 days
Generation	0.08%	0.26%	2.54%	7.11%	14.37%	21.39%	27.22%	33.01%
Oil and Gas	0.18%	0.48%	13.24%	31.50%	32.01%	32.09%	32.31%	32.38%
Petrochemicals	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%
Holding	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%	0.00%
12.31.2021	Undue	30 days	60 days	90 days	120 days	150 days	180 days	+ 180 days
Generation	0.06%	0.29%	2.08%	2.83%	4.67%	6.12%	6.24%	6.25%
Oil and Gas	0.04%	0.17%	0.77%	2.72%	6.88%	19.88%	21.97%	15.89%
Petrochemicals	0.00%	0.00%	0.01%	0.05%	0.12%	0.52%	0.52%	0.54%
Holding	0.00%	0.00%	0.01%	0.05%	0.12%	0.52%	0.52%	0.54%

Finally, although cash, cash equivalents and financial assets are also subject to the impairment requirements of IFRS 9, the identified impairment loss is immaterial.

Allowance of impairment of financial assets and other credits evolution as of December 31, 2023, 2022 and 2021, is detailed in Note 12.3.

The Company's maximum exposure to credit risk is based on the book value of each financial asset in the Consolidated Financial Statements. On the basis of the change in an assumption, while holding all other assumptions constant, a 5% increase/(decrease) in the estimated trade receivables' uncollectibility rate would result in US$ 0.05 million (decrease)/increase in 2023 fiscal year's results, before income tax.

6.2.1.3 Liquidity risk

The liquidity risk is associated with the Company's capacity to finance its commitments and conduct its business plans with stable financial sources, as well as with the indebtedness level and the financial debt maturities profile. The cash flow projection is made by the Financial Department.

The Company Management supervises updated projections on liquidity requirements to guarantee the sufficiency of cash and liquid financial instruments to meet operating and financing needs of the Company while keeping at all times a sufficient margin of unused credit facilities. In this way, the aim is that the Company does not breach indebtedness levels or the Covenants, applicable, of any credit facility. Those projections take into consideration the Company's debt financing plans, the meeting of the covenants and, if applicable, the external regulatory or legal requirements such as, for example, restrictions on the use of foreign currency. Additionally, the Financial Department regularly monitors the available credit for the Company, both in the local and international capital market as well as in the banking sector.

NOTE 6: (Continuation)

Excess cash and balances above working capital management requirements are managed by the Company's Treasury Department, which invests them in marketable securities, term deposits and mutual funds, selecting instruments having proper currencies and maturities, and an adequate credit quality and liquidity to meet cash needs estimated in the previously indicated projections.

The Company keeps its sources of financing diversified between banks and the capital market, and it is exposed to the refinancing risk at maturity.

It should be noted that the Company operates in an economic context in which main variables experience volatility as a result of political and economic events both domestically and internationally, as described in Note 1.2. that may potentially affect the cost of access to finance for emerging markets in general, and particularly for Argentina, and which in turn may potentially affect the Company's capacity to obtain financing for its operations in a timely manner and under acceptable and efficient terms, costs and conditions in line with the Company's business needs.

Furthermore, the restrictions imposed by the BCRA (see Note 2.5) with the purpose of regulating inflows and outflows in the MLC and other new restrictions which may be imposed in the future may affect the Company's capacity to access the MLC to acquire the foreign currency necessary to meet its financial obligations, such as debt principal and interest payments (including the CBs debt), and other additional payments abroad, or otherwise affect the Company's business and the results of its operations.

The Company's Management permanently monitors the evolution of situations affecting its business to determine possible steps to take and identify potential impacts on its assets and financial position.

It is worth highlighting that the Company currently has a strong level of liquidity that allows it to properly face such volatility.

The determination of the Company's liquidity index for fiscal years ended December 31, 2023 and 2022 is detailed below:

			12.31.2023		12.31.2022
Current assets			1,336		1,343
Current liabilities			521		631
Liquidity ratio			2.56		2.13

The following table includes an analysis of the Company trade receivables, other receivables and financial liabilities, grouped according to their maturity dates and considering the period remaining until their contractual maturity date from the date of the Consolidated Financial Statements. Derivative financial instruments are included in the analysis if their contractual maturities are essential for the understanding of the cash flow calendar. The amounts shown in the table are the contractual undiscounted cash flows.

NOTE 6: (Continuation)

As of December 31, 2023			Trade and other receivables		Trade and other payables (1)		Borrowings
Less than three months			261		223		63
Three months to one year			13		15		236
One to two years			10		31		277
Two to five years			6		6		907
More than five years			-		9		306
Non set maturity term			24		-		-
Total			314		284		1,789
As of December 31, 2022			Trade and other receivables		Trade and other payables (1)		Borrowings
Less than three months			412		231		289
Three months to one year			19		50		361
One to two years			6		12		1,022
Two to five years			12		3		313
More than five years			-		6		2,102
Non set maturity term			41		-		-
Total			490		302		4,087

(1)	Includes Lease Liabilities (see Note 19).

6.3Capital risk management

The aims of managing capital are to safeguard its capacity to continue operating as an on-going business with the purpose of generating return for its shareholders and benefits to other stakeholders, and keeping an optimal capital structure to reduce the cost of capital.

To keep or adjust its capital structure, the Company may adjust the amount of the dividends paid to its shareholders, reimburse capital to its shareholders, issue new shares, conduct stock repurchase programs or sell assets to reduce its debt.

In line with industry practices, the Company monitors its capital based on the leverage ratio. This ratio is calculated by dividing the net debt by the total capital. The net debt equals the total indebtedness (including current and non-current indebtedness) minus cash and cash equivalents and current financial assets at fair value through profit and loss. The total capital corresponds to the shareholders' equity as shown in the statement of financial position, plus the net debt.

NOTE 6: (Continuation)

Financial leverage ratios as at December 31, 2023 and 2022 were as follows:

			12.31.2023		12.31.2022
Total borrowings			1,448		1,613
Less: cash and cash equivalents, and financial assets at fair value through profit and loss			(730)		(692)
Net debt			718		921
Total capital			3,122		3,198
Leverage ratio			23.00%		28.80%

NOTE 7: SEGMENT INFORMATION

The Company is a fully integrated power company in Argentina, which participates in the electricity and oil and gas value chains.

Through its own activities, subsidiaries and share holdings in joint ventures, and based on the business nature, customer portfolio and risks involved, the following business segments have been identified:

Electricity Generation, principally consisting of the Company's direct and indirect interests in HINISA, HIDISA, Greenwind, VAR, CTB, TMB, TJSM and through its own electricity generation activities through thermal plants CTG, CPB, Piquirenda, CTLL, CTGEBA, Ecoenergía, CTPP, CTIW, the HPPL hydroelectric complex and PEPE II, PEPE III and PEPE IV wind farms. It is worth highlighting that the results of the segment's operations reflect the effects of the consolidation with Greenwind from August 12, 2022 to August 16, 2023 (see Notes 5.2.3 and 5.2.6) and with VAR as from December 16, 2022 (see Note 5.2.5).

Electricity Distribution, consisting of the Company's direct interest in Edenor until its disposal (see Note 5.2.1). As of December 31, 2021, the Company has classified the related results as discontinued operations.

Oil and Gas, principally consisting of the Company's interests in oil and gas areas and through its direct and indirect interest in CISA.

Petrochemicals, comprising of the Company's own styrenics operations and the catalytic reformer plant operations conducted in local plants.

Holding and Other Business, principally consisting of interests in joint businesses CITELEC and CIESA and their respective subsidiaries, which hold the concession over the high voltage electricity transmission nationwide and over gas transportation in the South of the country, respectively, interests in the associates OCP and Refinor (until its divestment detailed in Note 5.2.2), holding activities and financial investment transactions.

The Company manages its operating segment based on its individual net result in U.S. dollars.

NOTE 7: (Continuation)

		in million of US$
Consolidated profit and loss information for the year ended December 31, 2023		Generation		Oil and gas		Petrochemicals		Holding and others		Eliminations		Consolidated
Revenue - local market		648		402		359		14		-		1,423
Revenue - foreign market		-		161		148		-		-		309
Intersegment revenue		-		103		-		-		(103)		-
Cost of sales		(354)		(412)		(444)		-		103		(1,107)
Gross profit		294		254		63		14		-		625
Selling expenses		(2)		(49)		(15)		-		-		(66)
Administrative expenses		(50)		(74)		(6)		(55)		-		(185)
Exploration expenses		-		(7)		-		-		-		(7)
Other operating income		75		86		13		3		-		177
Other operating expenses		(27)		(32)		(7)		(22)		-		(88)
(Impairment) Recovery of impairment of property, plant and equipment, intangible assets and inventories		-		(38)		(3)		2		-		(39)
Share of profit from associates and joint ventures		(18)		-		-		16		-		(2)
Profit from sale of companies´ interest		-		-		-		9		-		9
Operating income		272		140		45		(33)		-		424
Financial income		2		2		-		7		(6)		5
Financial costs		(119)		(203)		(3)		(45)		6		(364)
Other financial results		280		(15)		15		278		-		558
Financial results, net		163		(216)		12		240		-		199
Profit before income tax		435		(76)		57		207		-		623
Income tax		(225)		29		(27)		(95)		-		(318)
Profit (Loss) of the year		210		(47)		30		112		-		305
Depreciation and amortization		96		166		5		-		-		267

NOTE 7: (Continuation)

		in million of US$
Consolidated profit and loss information for the year ended December 31, 2023		Generation		Oil and gas		Petrochemicals		Holding and others		Eliminations		Consolidated
Total profit (loss) of the year attributable to:
Owners of the company		207		(47)		30		112		-		302
Non-controlling interest		3		-		-		-		-		3
Consolidated financial position information as of Dcember 31, 2023
Assets		2,684		1,396		157		631		(146)		4,722
Liabilities		729		1,213		137		376		(146)		2,309
Net book values of property, plant and equipment		1,345		1,138		27		34		-		2,544
Additional consolidated information as of December 31, 2023
Increases in property, plant and equipment and right-of-use assets		259		556		7		5		-		827

NOTE 7: (Continuation)

	in million of US$
Consolidated profit and loss information for the year ended December 31, 2022		Generation		Oil and gas		Petrochemicals		Holding and others		Eliminations		Consolidated
Revenue - local market		663		370		425		20		-		1,478
Revenue - foreign market		-		159		192		-		-		351
Intersegment revenue		-		117		-		-		(117)		-
Cost of sales		(370)		(350)		(536)		-		117		(1,139)
Gross profit		293		296		81		20		-		690
Selling expenses		(3)		(45)		(17)		-		-		(65)
Administrative expenses		(39)		(60)		(5)		(38)		-		(142)
Other operating income		25		61		1		44		-		131
Other operating expenses		(5)		(26)		(6)		(9)		-		(46)
Impairment of property, plant and equipment, intangible assets and inventories		-		(30)		(2)		(6)		-		(38)
Impairment of financial assets		-		(2)		-		(2)		-		(4)
Share of profit from associates and joint ventures		65		-		-		40		-		105
Operating income		336		194		52		49		-		631
Financial income		1		2		-		9		(7)		5
Financial costs		(82)		(107)		(3)		(36)		7		(221)
Other financial results		72		(28)		6		116		-		166
Financial results, net		(9)		(133)		3		89		-		(50)
Profit before income tax		327		61		55		138		-		581
Income tax		(73)		(16)		(15)		(20)		-		(124)
Profit of the year		254		45		40		118		-		457
Depreciation and amortization		82		125		5		-		-		212

NOTE 7: (Continuation)

	in million of US$
Consolidated profit and loss information for the year ended December 31, 2022		Generation		Oil and gas		Petrochemicals		Holding and others		Eliminations		Consolidated
Total profit of the year attributable to:
Owners of the company		253		45		40		118		-		456
Non-controlling interest		1		-		-		-		-		1
Consolidated financial position information as of December 31, 2022
Assets		2,464		1,234		177		1,029		(162)		4,742
Liabilities		979		1,248		147		245		(161)		2,458
Net book values of property, plant and equipment		1,299		807		24		34		-		2,164
Additional consolidated information as of December 31, 2022
Increases in property, plant and equipment, intangibles assets and right-of-use assets (1)		115		324		7		36		-		482

(1)	It does not include US$ 389 million for the incorporation of assets related to the acquisition of the equity interests detailed in Notes 5.2.3 and 5.2.5.

NOTE 7: (Continuation)

	in million of US$
Consolidated profit and loss information for the year ended December 31, 2021		Generation		Distribution of energy		Oil and gas		Petrochemicals		Holding and others		Eliminations		Consolidated
Revenue - local market		656		-		282		310		22		-		1,270
Revenue - foreign market		-		-		58		180		-		-		238
Intersegment revenue		-		-		113		-		-		(113)		-
Cost of sales		(355)		-		(285)		(424)		-		113		(951)
Gross profit		301		-		168		66		22		-		557
Selling expenses		(2)		-		(22)		(13)		-		-		(37)
Administrative expenses		(31)		-		(46)		(4)		(21)		-		(102)
Other operating income		42		-		58		1		4		-		105
Other operating expenses		(5)		-		(28)		(3)		(22)		-		(58)
Impairment of intangible assets and inventories		(2)		-		-		(2)		-		-		(4)
Recovery of impairment of financial assets		-		-		-		-		1		-		1
Share of profit from associates and joint ventures		47		-		-		-		53		-		100
Profit from acquisition of companies´ interest		-		-		-		-		17		-		17
Operating income		350		-		130		45		54		-		579
Financial income		4		-		3		-		4		(1)		10
Financial costs		(46)		-		(103)		(3)		(34)		1		(185)
Other financial results		(14)		-		(16)		(2)		18		-		(14)
Financial results, net		(56)		-		(116)		(5)		(12)		-		(189)
Profit before income tax		294		-		14		40		42		-		390
Income tax		(75)		-		8		(12)		2		-		(77)
Profit of the year from continuing operations		219		-		22		28		44		-		313
Loss of the year from discontinued operations		-		(75)		-		-		-		-		(75)
Profit (loss) of the year		219		(75)		22		28		44		-		238
Depreciation and amortization		88		-		114		3		-		-		205

NOTE 7: (Continuation)

								in million of US$
Consolidated profit and loss information for the year ended December 31, 2021		Generation		Distribution of energy		Oil and gas		Petrochemicals		Holding and others		Eliminations		Consolidated
Total profit (loss) of the year attributable to:
Owners of the company		218		(39)		22		28		44		-		273
Non-controlling interest		1		(36)		-		-		-		-		(35)
Consolidated financial position information as of December 31, 2021
Assets		1,670		-		1,157		176		1,067		(209)		3,861
Liabilities		525		-		1,324		166		264		(209)		2,070
Net book values of property, plant and equipment		969		-		636		22		32		-		1,659
Additional consolidated information as of December 31, 2021
Increases in property, plant and equipment, intangible assets and right-of-use assets		39		-		213		6		6		-		264

NOTE 8: REVENUE

		12.31.2023		12.31.2022		12.31.2021
Energy sales in Spot Market		196		210		167
Energy sales by supply contracts		363		346		380
Fuel supply		87		103		104
Other sales		2		4		5
Generation sales subtotal		648		663		656
Gas sales		432		383		231
Oil sales		121		136		99
Other sales		10		10		10
Oil and gas sales subtotal		563		529		340
Products from catalytic reforming sales		217		270		185
Styrene sales		79		96		84
Synthetic rubber sales		78		106		99
Polystyrene sales		131		141		119
Other sales		2		4		3
Petrochemicals sales subtotal		507		617		490
Technical assistance and administration services sales		14		20		22
Other		-		-		-
Holding and others subtotal		14		20		22
Total revenue (1)		1,732		1,829		1,508

(1)	Revenues from CAMMESA represent 33%, 31% and 38% of total revenues for the fiscal years ended December 31, 2023, 2022 and 2021, respectively, and correspond mainly to the Generation and Oil & Gas segments.

NOTE 9: COST OF SALES

		12.31.2023		12.31.2022		12.31.2021
Inventories at the beginning of the year		173		155		116
Plus: Charges of the year
Purchases of inventories, energy and gas		411		502		433
Salaries and social security charges		85		79		59
Employees benefits		17		15		13
Defined benefit plans		8		5		4
Works contracts, fees and compensation for services	111		97		73
Property, plant and equipment depreciation		254		202		194
Intangible assets amortization		5		1		1
Right-of-use assets amortization		1		3		5
Energy transportation		9		8		6
Transportation and freights		20		16		13
Consumption of materials		27		30		26
Penalties		2		1		2
Maintenance		47		61		52
Canons and royalties		92		89		65
Environmental control		4		5		4
Rental and insurance		31		31		27
Surveillance and security		5		4		3
Taxes, rates and contributions		7		5		4
Other		3		3		6
Total charges of the year		1,139		1,157		990
Less: Inventories at the end of the year		(205)		(173)		(155)
Total cost of sales		1,107		1,139		951

NOTE 10: OTHER ITEMS OF THE STATEMENT OF COMPREHENSIVE INCOME

10.1 Selling expenses

			12.31.2023		12.31.2022		12.31.2021
Salaries and social security charges			5		5		3
Employees benefits			1		1		-
Fees and compensation for services			3		4		3
Taxes, rates and contributions			13		14		11
Transportation and freights			43		40		18
Other			1		1		2
Total selling expenses			66		65		37

10.2Administrative expenses

			12.31.2023		12.31.2022		12.31.2021
Salaries and social security charges			58		50		34
Employees benefits			10		8		5
Defined benefit plans			18		9		7
Fees and compensation for services			29		30		32
Compensation agreements			37		19		2
Directors' and Sindycs' fees			7		7		6
Property, plant and equipment depreciation			7		6		5
Maintenance			2		2		2
Transport and per diem			2		2		1
Rental and insurance			1		1		1
Surveillance and security			1		1		-
Taxes, rates and contributions			8		6		5
Communications			1		1		1
Other			4		-		1
Total administrative expenses			185		142		102

10.3Exploration expenses

			12.31.2023		12.31.2022		12.31.2021
Derecognition of unproductive wells			(7)		-		-
Total exploration expenses			(7)		-		-

NOTE 10: (Continuation)

10.4 Other operating income and expenses

	Note		12.31.2023		12.31.2022		12.31.2021
Other operating income
Insurance recovery			1		-		3
Services provided to third parties			1		1		2
Results from property, plant and equipment sale and derecognition			1		2		1
Result from intangible assets sale			-		2		2
Expenses recovery			8		-		-
Contingencies recovery			-		-		13
Tax charges recovery			-		-		2
Contractual indemnity			7		-		-
Commercial interests			70		27		27
GasAr Plan			55		56		51
Compensation for arbitration award (1)			-		37		-
Fair value of consortiums' previous interest	5.2.6		7		-		-
Export Increase Program			24		-		-
Other			3		6		4
Total other operating income			177		131		105
Other operating expenses
Provision for contingencies			(8)		(4)		(16)
Provision for environmental remediation			(4)		-		(15)
Results for property, plant and equipment sale and derecognition			(2)		-		-
Tax on bank transactions			(18)		(14)		(13)
PAIS import tax			(5)		-		-
Donations and contributions			(3)		(2)		(2)
Institutional promotion			(4)		(3)		(3)
Costs of concessions agreements completion			(5)		-		-
Contractual penalty			(7)		-		-
Readjustment of investment plan (2)			-		(9)		-
Royalties GasAr Plan			(8)		(8)		(5)
Ecuador's transactional agreement			(5)		-		-
Impairment of other receivables			(5)		-		-
Other contractual expenses			(6)		-		-
Other			(8)		(6)		(4)
Total other operating expenses			(88)		(46)		(58)

(1)	Corresponding to the final award rendered on August 3, 2022 by the Arbitration Court partially upholding EcuadorTLC's (currently PB18) claim against Petroecuador for certain breaches of the transportation agreement executed on December 31, 2008.

(2)	Corresponding to the investment plan's readjustment bond at the Sierra Chata block approved by Provincial Executive Order No. 1,262/22 dated June 29, 2022.

NOTE 10: (Continuation)

10.5 Financial results

		12.31.2023		12.31.2022		12.31.2021
Financial income
Financial interests			2		1		-
Other interests			3		4		10
Total financial income			5		5		10
Financial costs
Financial interests (1)			(304)		(172)		(137)
Commercial interests			(1)		(1)		-
Fiscal interests			(47)		(38)		(38)
Other interests			(4)		(5)		(3)
Bank and other financial expenses			(8)		(5)		(7)
Total financial costs			(364)		(221)		(185)
Other financial results
Foreign currency exchange difference, net			123		80		3
Changes in the fair value of financial instruments			444		110		(15)
Result from present value measurement			(10)		(14)		(1)
Result from exchange of CB			-		(14)		-
Result from repurchase of CB			1		6		-
Other financial results			-		(2)		(1)
Total other financial results			558		166		(14)
Total financial results, net			199		(50)		(189)

(1)	Net of US$ 21 million and US$ 11 million borrowing costs capitalized in property, plant and equipment for the years ended December 31, 2023 and 2022, respectively. There are no capitalized borrowing costs in the fiscal year ended December 31, 2021.

NOTE 10: (Continuation)

10.6Income tax

The breakdown of income tax charge is:

			12.31.2023		12.31.2022		12.31.2021
Current tax			19		99		67
Deferred tax			272		46		10
Difference between previous fiscal year income tax provision and the income tax statement			27		(21)		-
Total income tax - Loss			318		124		77

Below is a reconciliation between income tax expense and the amount resulting from application of the tax rate on the income before taxes:

			12.31.2023		12.31.2022		12.31.2021
Profit before income tax			623		581		390
Current income tax rate			35%		35%		35%
Income tax at the statutary tax rate			218		203		138
Share of profit from companies			1		(37)		(40)
Non-taxable results			(17)		(3)		(1)
Effects of exchange differences and other results associated with the valuation of the currency, net			752		275		79
Effects of valuation of property, plant and equipment, intangible assets and financial assets			(1,146)		(575)		(269)
Effect of change in tax rate			-		-		(6)
Effect for tax inflation adjustment			501		253		169
Unrecognized deferred assets			-		-		4
Difference between previous fiscal year income tax and deferred tax provision and the income tax statement			3		2		1
Non-deductible cost			9		4		3
Impairment on deferred tax assets			(3)		2		-
Other			-		-		(1)
Total income tax - Loss			318		124		77

NOTE 11: NON-FINANCIAL ASSETS AND LIABILITIES

11.1 Property, plant and equipment

			Original values
Type of good			At the beginning		Increases (1)		Transfers		Decreases		Impairment		At the end
Lands			14		-		-		-		-		14
Buildings			143		-		3		(2)		-		144
Equipment and machinery			1,916		1		175		(132)		-		1,960
Wells			992		15		358		(21)		(149)		1,195
Mining property			181		21		15		-		(19)		198
Vehicles			10		2		1		(2)		-		11
Furniture and fixtures and software equipment			59		1		2		-		-		62
Communication equipments			3		-		-		(2)		-		1
Materials, spare parts and tools			36		93		(85)		-		-		44
Petrochemical industrial complex			29		-		3		-		-		32
Civil works			3		-		22		(1)		-		24
Work in progress			254		547		(381)		-		-		420
Advances to suppliers			43		134		(113)		-		-		64
Total at 12.31.2023			3,683		814		-		(160)		(168)		4,169
Total at 12.31.2022			3,040		745		-		(2)		(100)		3,683

(1)	Includes US$ 21 million and U$S 11 million corresponding to capitalized financial costs in the fiscal year ended December 31, 2023 and 2022.

Additionally, as of December 31, 2022, it includes U$S 295 million resulting from the incorporation of assets related to the acquisition of the equity interests detailed in Notes 5.2.3 and 5.2.5.

NOTE 11: (Continuation)

			Depreciation		Net book values
Type of good			At the beginning		Decreases		For the year (1)		Impairment		At the end		At 12.31.2023 (2)		At 12.31.2022
Lands			-		-		-		-		-		14		14
Buildings			(76)		-		(7)		-		(83)		61		67
Equipment and machinery			(639)		14		(123)		-		(748)		1,212		1,277
Wells			(589)		10		(112)		113		(578)		617		403
Mining property			(134)		-		(7)		17		(124)		74		47
Vehicles			(8)		1		(1)		-		(8)		3		2
Furniture and fixtures and software equipment			(52)		-		(5)		-		(57)		5		7
Communication equipments			(1)		-		-		-		(1)		-		2
Materials, spare parts and tools			(3)		-		-		-		(3)		41		33
Petrochemical industrial complex			(17)		-		(5)		-		(22)		10		12
Civil works			-		-		(1)		-		(1)		23		3
Work in progress			-		-		-		-		-		420		254
Advances to suppliers			-		-		-		-		-		64		43
Total at 12.31.2023			(1,519)		25		(261)		130		(1,625)		2,544
Total at 12.31.2022			(1,381)		-		(208)		70		(1,519)				2,164

(1)	As of December 31, 2023, the composition of the segments is as follows: Generation: US$ 90 million; Oil and gas: US$ 166 million; and Petrochemicals: US$ 5 million.

NOTE 11: (Continuation)

11.1.1 Impairment of Property, plant and equipment

The Company regularly monitors the existence of events or changes in circumstances which may indicate that the book value of property, plant and equipment may not be recoverable in accordance with the policy described in Notes 4.9 and 6.1.1.

In the Generation segment, as of December 31, 2023, 2022 and 2021, the Company did not identify indications that could impact the assumptions considered in the recoverability assessment performed as of June 30, 2021. It is worth highlighting that the Company has not recorded any property, plant and equipment impairment losses as a result of that recoverability assessment; however, intangible asset impairment losses were recognized for the HIDISA plant in the amount of US$ 2 million.

As of December 31, 2023 and June 30, 2022, due to Company's strategic reasons and aiming to focus its investments in the development and exploitation of its unconventional gas and oil reserves in the Vaca Muerta formation, the Company, in line with the affected block's Joint Venture members' strategy, decided to reschedule or suspend certain future drilling and workover activities for the next few years, which involved the recategorization of reserves to contingent resources.

In view of the above-mentioned indications of impairment, the Company has determined the recoverable amount of the CGU Rincón del Mangrullo and el Tordillo / la Tapera making up the Oil & Gas segment as of December 31, 2023 and June 30, 2022.

The methodology used in the estimation of the recoverable amount consisted on calculating each CGU value in use on the present value of future net cash flows expected to be generated by the CGU, discounted with a rate reflecting the weighted average costs of the invested capital.

Cash flows were prepared based on estimates on the future behavior of certain key assumptions for the determination of the value in use, including the following: (i) reference prices for products; (ii) demand projections per type of product; (iii) costs evolution; and; (iv) macroeconomic variables such as inflation and exchange rates, etc.

NOTE 11: (Continuation)

Oil & Gas segment

As of December 31, 2023 and June 30, 2022, the recoverability assessment of the affected CGU of the Oil and Gas segment, resulted in the recognition of impairment losses for U$S 37.7 million in the Rincón del Mangrullo and el Tordillo / la Tapera blocks and US$ 30 million in the Rincón del Mangrullo block, respectively.

The key assumptions used to calculate the recoverable amount considered: i) the reschedule or suspension of drilling and workover activities; and ii) a 12.2% and 12.4% after-tax WACC rate, respectively.

Finally, it is important to highlight that as of December 31, 2023 and 2022, the book value of the Oil and gas segment assets, including the goodwill assigned to the segment, does not exceed its recoverable value.

NOTE 11: (Continuation)

11.2 Intangible assets

		Original values
Type of good		At the beginning			Increases (1)		Decreases		Impairment (2)		At the end
Concession agreements		2			-		-		-		2
Goodwill		35			-		-		-		35
Intangible identified in acquisitions of companies		101			-		(30)		-		71
Digital assets		7			-		(9)		2		-
Total at 12.31.2023		145			-		(39)		2		108
Total at 12.31.2022		44			125		(18)		(6)		145
		Amortization
Type of good		At the beginning			For the year		Impairment (2)		At the end
Concession agreements		(2)			-		-		(2)
Intangible identified in acquisitions of companies		(5)			(5)		-		(10)
Total at 12.31.2023		(7)			(5)		-		(12)
Total at 12.31.2022		(6)			(1)		-		(7)
		Net book values
Type of good		At 12.31.2023			At 12.31.2022
Goodwill		35			35
Intangible identified in acquisitions of companies		61			96
Digital assets		-			7
Total at 12.31.2023		96
Total at 12.31.2022					138

(1)	As of December 31, 2022, it includes US$ 94 million for the incorporation of assets from the acquisition of equity interests detailed in Notes 5.2.3 and 5.2.5.

(2)

The sale of the digital assets at market price resulted in the recording of an impairment recovery for US$ 2 million as of December 31, 2023. As of December 31, 2022, the recoverability of the digital assets was affected by their market value at closing, resulting in the recording of impairment losses for US$ 6 million.

NOTE 11: (Continuation)

11.3 Deferred tax assets and liabilities

The composition of the deferred tax assets and liabilities is as follows:

	12.31.2022		Profit (loss)		Sale of subsidiary		12.31.2023
Tax loss carryforwards	19		125		-		144
Property, plant and equipment	151		(151)		-		-
Trade and other receivables	4		(3)		-		1
Provisions	59		(6)		-		53
Salaries and social security payable	1		-		-		1
Defined benefit plans	8		(6)		2		4
Other	1		(1)		-		-
Deferred tax asset	243		(42)		2		203
Property, plant and equipment	(79)		(188)		45		(222)
Intangible assets	(35)		1		-		(34)
Investments in companies	(8)		1		-		(7)
Inventories	(19)		(26)		-		(45)
Financial assets at fair value through profit and loss	(15)		(3)		-		(18)
Trade and other receivables	(23)		12		1		(10)
Taxes payables	(2)		2		-		-
Tax inflation adjustment	(138)		(28)		3		(163)
Other	-		(1)		-		(1)
Deferred tax liability	(319)		(230)		49		(500)
Deferred tax (liability) asset	(76)		(272)		51		(297)

NOTE 11: (Continuation)

	12.31.2021		Profit (loss)		Increases for incorporation		12.31.2022
Tax loss carryforwards	13		6		-		19
Property, plant and equipment	80		71		-		151
Financial assets at fair value through profit and loss	3		(3)		-		-
Trade and other receivables	5		(1)		-		4
Provisions	57		2		-		59
Salaries and social security payable	-		1		-		1
Defined benefit plans	9		(1)		-		8
Other	-		1		-		1
Deferred tax asset	167		76		-		243
Property, plant and equipment	-		-		(79)		(79)
Intangible assets	(13)		-		(22)		(35)
Investments in companies	(11)		3		-		(8)
Inventories	(10)		(9)		-		(19)
Financial assets at fair value through profit and loss	(14)		(1)		-		(15)
Trade and other receivables	(31)		8		-		(23)
Taxes payables	(3)		1		-		(2)
Tax inflation adjustment	(1)		(124)		(13)		(138)
Deferred tax liability	(83)		(122)		(114)		(319)
Deferred tax asset (liability)	84		(46)		(114)		(76)

Deferred tax assets and liabilities are offset in the following cases: a) when there is a legally enforceable right to offset tax assets and liabilities; and b) when deferred income tax charges are associated with the same fiscal authority. The following table shows the figures disclosed on the Consolidated Statement of Financial Position, which for its determination, were adequately compensated:

	12.31.2023		12.31.2022
Deferred tax asset	-		36
Deferred tax liability	(297)		(112)
Deferred tax liability	(297)		(76)

NOTE 11: (Continuation)

11.4 Inventories

		12.31.2023		12.31.2022
Current
Materials and spare parts		129		104
Advances to suppliers		4		8
In process and finished products		72		61
Total (1)		205		173

(1)	It includes impairment loss as a result of the performed recoverability assessment for US$ 3 million and US$ 2 million as of December 31, 2023 and 2022, acoording with the policy described in Note 4.13.

11.5 Provisions

		12.31.2023		12.31.2022
Non-Current
Contingencies		109		107
Asset retirement obligation and wind turbines decommisioning		26		25
Environmental remediation		15		15
Total Non-Current		150		147
Current
Asset retirement obligation and wind turbines decommisioning		3		2
Environmental remediation		2		2
Other provisions		1		-
Total Current		6		4

NOTE 11: (Continuation)

The evolution of the provisions is set out below:

		12.31.2023
		Contingencies		Asset retirement obligation and decommisioning of wind turbines		Environmental remediation
At the beginning of the year		107		27		17
Increases		15		6		3
Decreases		(4)		-		(1)
Foreign currency exchange difference		(9)		-		-
Reversal of unused amounts		-		(4)		(2)
At the end of the year		109		29		17
		12.31.2022
		Contingencies		Asset retirement obligation and decommisioning of wind turbines		Environmental remediation
At the beginning of the year		106		21		18
Increases		5		6		-
Increases for incorporation		-		1		-
Decreases		(1)		-		(1)
Foreign currency exchange difference		(2)		-		-
Reversal of unused amounts		(1)		(1)		-
At the end of the year		107		27		17

NOTE 11: (Continuation)

		12.31.2021
		Contingencies		Asset retirement obligation and decommisioning of wind turbines		Environmental remediation
At the beginning of the year		103		21		3
Increases		16		3		15
Decreases		-		(1)		-
Reversal of unused amounts (1)		(13)		(2)		-
At the end of the year		106		21		18

(1)	Includes recovery of contingencies of US$ 12.5 million related to the waive of the timely granted dispatch of Las Armas Wind Farm (see Note 2.1.2.3).

11.5.1 Provision for Environmental remediation

The Company is subject to extensive environmental regulations in Argentina. The Company's management believes that its current operations are in compliance with applicable environmental requirements, as currently interpreted and enforced, including regulatory remediation commitments assumed. The Company undertakes environmental impact studies for new projects and investments and, to date, environmental requirements and restrictions imposed on these new projects have not had any material adverse impact on Pampa's business.

In particular, the Province of La Pampa has submitted a claim to the Company regarding the abandonment of certain wells and the execution of certain tasks associated with the relinquishment of the Jagüel de los Machos and Medanito blocks, which took place in 2015 and 2016, respectively. The Company has challenged the different administrative acts passed by the provincial authorities (including a governor's executive order) and is addressing claims for the Jagüel de los Machos block in the judicial jurisdiction. Even though the province answered the complaint in the month of March 2021, the Company has started formal negotiations to resolve the dispute, agreeing on the suspension of procedural time limits. During 2021, regarding these claims and based on the progress of the ongoing negotiations, the Company recorded provisions for the estimate of remediation work costs to be incurred in these blocks.

The Company has performed a sensitivity analysis relating to the discount rate. The 1% increase or decrease in the discount rate would not have a significant impact on the Company's results of operations.

NOTE 11: (Continuation)

11.5.2 Asset retirement obligations and wind turbines decommissioning

Pursuant to the regulations in force in Argentina, where it develops its oil and gas exploration and production operations, the Company is under an obligation to incur costs associated with the plugging and abandonment of wells. Furthermore, pursuant to the associated usufruct agreements, the Company is under an obligation to decommission wind turbines in wind farms. The Company does not have legally restricted assets for the cancellation of these obligations.

The Company has performed a sensitivity analysis relating to the discount rate. The 1% increase or decrease in the discount rate would not have a significant impact on the Company's results of operations.

11.5.3 Provision for legal proceedings

The Company (directly or indirectly through subsidiaries) is a party to several civil, commercial, contentious-administrative, tax, custom and labor proceedings and claims that arise in the ordinary course of its business. In determining a proper level of provision, the Company has considered its best estimate mainly with the assistance of legal and tax advisors.

The determination of estimates may change in the future due to new developments or unknown facts at the time of evaluation of the provision. As a consequence, the adverse resolution of the evaluated proceedings and claims could exceed the established provision.

As of December 31, 2023, the Company has recorded provisions for US$ 100.4 million in relation to the following processes:

-	There are a significant number of files pending before the National Tax Court regarding gasoline exports, where the tax entity challenges the tariff heading assigned by Petrobras Argentina S.A. in 2008-2014. The Treasury's position involves a higher export duty rate.

-

Petrobras Operaciones S.A. ("POSA") has filed an international arbitration claim against the Company before the International Chamber of Commerce ("ICC") on account of alleged breaches to the Assignment Agreement entered into between Petrobras Argentina S.A. (currently Pampa) and POSA in 2016 for the transfer of a 33.6% interest in the "Río Neuquén" Concession. The breaches alleged by POSA in its arbitration claim consist of the failure to transfer certain assets associated with the assigned interest, and differences in the calculation of adjustments in the assignment price. The arbitration is conducted according to the ICC Rules of Arbitration, the applicable law is the one of the Republic of Argentina, and the seat of arbitration is Buenos Aires, Argentina. On April 30, 2021, POSA filed its claim memorial, and on September 15, 2021, the Company submitted its answer to the claim memorial and counterclaim. On December 15, 2021, POSA submitted its answer to the counterclaim. As of the date of issuance of these Consolidated Financial Statements, the arbitration award is pending issuance by the Arbitration Court .

NOTE 11: (Continuation)

-

The Company filed an international arbitration claim against Petrobras International Braspetro B.V. ("PIB BV") on account of fraudulent representations and omissions associated with certain export transactions under the share purchase agreement executed on May 13, 2016, whereby the Company acquired 67.2% of Petrobras Argentina S.A.'s capital stock. The arbitration is held under the ICC Arbitration Rules; the applicable law is the one of the State of New York, and the seat of arbitration is New York. On April 29, 2021, the Company filed its claim memorial and PIB BV submitted its counter-memorial and counterclaim seeking the payment of a percentage over the difference between the amount estimated for certain contingencies detected in the purchase process and the amount actually paid for them. On July 7, 2021, the Company and PIB BV submitted their respective answers. On November 5, 2021, the Company and PIB BV submitted their replications, and on December 20, 2021, their rejoinders to the complaints. On November 9, 2023, the ICC notified the parties of the Final Award rendered by the Court on November 2, 2023, resolving to (i) dismiss the Company's claims; (ii) dismiss most of PIB BV's counterclaims, ordering the Company to pay the amount of US$ 3.2 million plus interest from March 31, 2021; and (iii) dismiss all other claims of the parties. As of the date of issuance of these Consolidated Financial Statements, the Company has paid PIB BV the amounts established in the Final Award.

Additionally, the Company has recorded provisions for civil, commercial, administrative, labor, tax and customs complaints brought against the Company corresponding to atomized claims with individual unsubstantial amounts, as well as charges for judicial costs and expenses which, as of December 31, 2023, amount to US$ 8.5 million.

11.6 Income tax and minimum notional income tax liability

		12.31.2023		12.31.2022
Non-current
Income tax, net of witholdings and advances		50		161
Minimum notional income tax		5		18
Total non-current		55		179
Current
Income tax, net of witholdings and advances		17		5
Total current		17		5

NOTE 11: (Continuation)

11.6.1 Income tax liability

The Company accrued the effect of the tax inflation adjustment in the calculation of the current and deferred income tax provision for each of the fiscal years in which the cumulative CPI variation provided by Law No. 27,430 was exceeded, except in those cases when, on being interim fiscal periods, the mentioned legal parameter has not been exceeded for each of the annual periods.

The tax inflation adjustment mechanism set out in Title VI and different supplementary sections of the Income Tax Law is inconsistent in certain aspects generating a confiscatory lien, including, but not limited to, the failure to update tax losses and the cost of acquisitions or investments made before January 1, 2018, which bears resemblance with the parameters in re "Candy S.A.", where the CSJN ordered the application of the inflation adjustment mechanism.

As of December 31, 2023, the Company and its subsidiaries hold a provision for the additional income tax liabilities that should have been assessed due to the stated reasons. The amount provisioned for the periods not prescribed and/or those without a final and conclusive judgment in favor of the Company, including compensatory interest, amounts to U$S 50 million.

11.6.2 Minimum Notional Income Tax liability

The Company and its subsidiaries have filed a petition for declaratory relief under Sect. 322 of the Federal Code of Civil and Commercial Procedure to gain assurance as to the application of the minimum notional income tax for the fiscal years 2011-2018 based on CSJN's decision in re "Hermitage" passed on June 15, 2010. In this established precedent, the CSJN declared the unconstitutionality of this tax on the grounds that it is unreasonable and it breaches the taxpaying capacity principle when the absence of taxable income in the period evidences that the income presumed by the legislator has not existed.

However, on August 26, 2021, the CSJN dismissed the tax refund claim lodged by the Company for the 2008 and 2009 periods alleging that, despite the evidenced tax losses, the existence of accounting profits is a manifestation of the taxpaying capacity and, therefore, the precepts of the Hermitage precedent are not met.

Considering the CSJN's current position, and the prescribed periods, the Company and its subsidiaries have recorded, for periods presenting tax losses and accounting profits, liabilities on the amount of the applicable interest on the Notional Income Tax, plus the determined tax provision for those cases in which Minimum Notional Income Tax is not considered to be computable as an Income Tax advance payment. This liability is disclosed under "Non-Current Income tax and minimum notional income tax provision". The mentioned liability amounts to U$S 5 million.

NOTE 11: (Continuation)

11.7 Tax liabilities

		12.31.2023		12.31.2022
Current
Value added tax		-		5
Personal assets tax provision		3		4
Tax withholdings to be deposited		3		5
Royalties		6		12
Other		2		2
Total current		14		28

11.8 Defined benefits plans

The main characteristics of benefit plans granted to Company employees are detailed below:

(i)

Pension and retirement benefits: Benefit plan whereby Company employees, in some cases covered by certain collective bargaining agreements, meeting certain conditions are eligible to receive upon retirement, and in some cases, disability or death, a certain number of salaries according to the provisions of the plan or collective bargain agreement, if applicable.

(ii)

Compensatory plan: Benefit plan whereby some of the Company employees meeting certain conditions are eligible to receive upon retirement a certain amount according to the provisions of the plan (based on the last computable salary and the number of years working for the Company) after deducting the benefits from the pension system. The plan, until 2003, called for a contribution to a fund exclusively by the Company and without any contribution by the employees. These contributions were derived to a trust fund and were invested in U.S. dollar-denominated money market instruments in order to preserve the accumulated capital and obtain a return in line with a moderate risk profile. Funds were mainly invested in U.S. government bonds, commercial papers rated A1 or P1, AAAm- rated mutual funds and time deposits in banks rated A+ or higher in the United States of America, in accordance with the Trust Agreement dated on March 27, 2002 entered with The Bank of New York Mellon, duly amended by the Permitted Investment Letter dated on September 14, 2006. The Bank of New York Mellon is the trustee and Willis Towers Watson is the managing agent. In case there is an excess, duly certified by an independent actuary, of the funds to be used to settle the benefits granted by the plan, the Company will be entitled to choose to use it, in which case it may have to notify the trustee thereof.

NOTE 11: (Continuation)

As of December 31, 2023, 2022 and 2021, the most relevant actuarial information corresponding to the described benefit plans is the following:

	12.31.2023
	Present value of the obligation		Present value of assets		Net liability at the end of the year
At the beginning of the year	38		(4)		34
Items classified in profit or loss
Current services cost	1		-		1
Interest cost	29		(4)		25
Items classified in other comprehensive income
Actuarial loss (gain)	7		(2)		5
Benefit payments	(3)		-		(3)
(Gain) Loss on exchange difference	(49)		6		(43)
At the end of the year	23		(4)		19
	12.31.2022
	Present value of the obligation		Present value of assets		Net liability at the end of the year
At the beginning of the year	33		(4)		29
Items classified in profit or loss
Current services cost	1		-		1
Interest cost	15		(2)		13
Items classified in other comprehensive income
Actuarial loss	9		-		9
Benefit payments	(3)		-		(3)
(Gain) Loss on exchange difference	(17)		2		(15)
At the end of the year	38		(4)		34

NOTE 11: (Continuation)

	12.31.2021
	Present value of the obligation		Present value of assets		Net liability at the end of the year
At the beginning of the year	25		(4)		21
Items classified in profit or loss
Current services cost	1		-		1
Interest cost	13		(3)		10
Items classified in other comprehensive income
Actuarial loss	1		2		3
Benefit payments	(2)		-		(2)
(Gain) Loss on exchange difference	(5)		1		(4)
At the end of the year	33		(4)		29

As of December 31, 2023, 2022 and 2021, the breakdown of net liabilities per type of plan is as follows: a) US$ 10 million, US$ 17 million and US$ 15 million correspond to the Pension and Retirement Benefits Plan and b) US$ 10 million, US$ 17 million and US$ 14 million correspond to the Compensatory Plan, respectively.

Estimated expected benefits payments for the next ten years are shown below. The amounts in the table represent the undiscounted cash flows and therefore do not reconcile to the obligations recorded at the end of the year.

	12.31.2023
Less than one year	3
One to two years	2
Two to three years	2
Three to four years	2
Four to five years	2
Six to ten years	9

NOTE 11: (Continuation)

Significant actuarial assumptions used were as follows:

	12.31.2023		12.31.2022		12.31.2021
Real discount rate	5%		5%		5%
Real wage increase rate	1%		1%		1%
Inflation rate	156%		118%		54%

The following sensitivity analysis shows the effect of a variation in the discount rate and salaries increase on the obligation amount:

	12.31.2023
Discount rate: 4%
Obligation	25
Variation	2
	10%
Discount rate: 6%
Obligation	21
Variation	(2)
	(9%)
Real wage increase rate: 0%
Obligation	22
Variation	(1)
	(3%)
Real wage increase rate: 2%
Obligation	24
Variation	1
	4%

The sensitivity analyses are based on a change in an assumption while holding all other assumptions constant. In practice, this is unlikely to occur, and changes in some of the assumptions may be correlated. Therefore, the presented analysis may not be representative of the actual change in the defined benefit obligation. The methods and types of assumptions used in preparing the sensitivity analysis did not change compared to the prior period.

NOTE 11: (Continuation)

11.9 Salaries and social security payable

		12.31.2023		12.31.2022
Current
Salaries and social security contributions		3		5
Provision for vacations		5		8
Provision for gratifications and annual bonus for efficiency		11		19
Total current		19		32

NOTE 12: FINANCIAL ASSETS AND LIABILITIES

12.1Financial assets at amortized cost

		12.31.2023		12.31.2022
Non-current
Term deposit		-		101
Notes receivable		-		1
Total non-current		-		102
Current
Term deposit		101		-
Notes receivable		4		8
Total current		105		8

Due to the short-term nature of investments at amortized cost, it is considered that their book value does not differ from their fair value. For non-current investments at amortized cost, fair values also do not differ significantly from book values.

NOTE 12: (Continuation)

12.2Financial assets at fair value through profit and loss

		12.31.2023		12.31.2022
Non-current
Shares		35		27
Total non-current		35		27
Current
Government securities		389		279
Corporate bonds		79		116
Shares		88		160
Mutual funds		3		31
Total current		559		586

12.3Trade and other receivables

	Note		12.31.2023		12.31.2022
Non-Current
Related parties	16		11		17
Tax credits			1		2
Receivables for sale of associates			1		-
Contractual indemnity receivable			4		-
Other			1		1
Other receivables			18		20
Total non-current			18		20

NOTE 12: (Continuation)

	Note		12.31.2023		12.31.2022
Current
Receivables			105		141
CAMMESA			100		165
Related parties	16		5		5
Impairment of financial assets			(1)		(6)
Trade receivables, net			209		305
Current
Related parties	16		7		7
Tax credits			10		14
Receivables for complementary activities			1		-
Prepaid expenses			5		14
Guarantee deposits			19		27
Expenses to be recovered			6		15
Insurance to be recovered			4		-
Receivables for acquisition of subsidiary			-		7
Receivables for sale of associates			1		4
Receivables for financial instruments sale			-		1
GasAr Plan			11		32
Receivables for arbitration award			-		37
Contractual indemnity credit			2		-
Advances to employees			10		-
Other			11		7
Other receivables, net			87		165
Total current			296		470

Due to the short-term nature of trade and other receivables, its book value is not considered to differ from its fair value. For non-current trade and other receivables, fair values do not significantly differ from book values.

NOTE 12: (Continuation)

The movements in the impairment of financial assets were as follows:

			12.31.2023		12.31.2022		12.31.2021
At the beginning of the year			6		9		16
Impairment			1		1		1
Utilization			-		(1)		-
Reversal of unused amounts			(1)		-		(6)
Foreign currency exchange difference			(5)		(3)		(2)
At the end of the year			1		6		9

12.4Cash and cash equivalents

		12.31.2023		12.31.2022
Banks		31		11
Mutual funds		140		95
Total		171		106

12.5Borrowings

			12.31.2023		12.31.2022
Non-Current
Financial borrowings			-		108
Corporate bonds			1,224		1,232
Total non-current			1,224		1,340
Current
Bank overdrafts			31		59
Financial borrowings			67		51
Corporate bonds			126		163
Total current			224		273
Total			1,448		1,613

As of December 31, 2023 and 2022, the fair values of the Company's CB amount approximately to US$ 1,350 million and US$ 1,435 million, respectively. Such values were calculated on the basis of the determined market price of the Company's CB at the end of each year (fair value level 1).

The carrying amounts of short-term borrowings and bank overdrafts approximate their fair value due to their short-term maturity.

The long-term borrowings were measured at amortized cost, which does not differ significantly from its fair value.

As of the date of issuance of these Consolidated Financial Statements, the Company is in compliance with the covenants established in its indebtedness contracts.

NOTE 12: (Continuation)

12.5.1 Movements in borrowings:

			12.31.2023		12.31.2022		12.31.2021
At the beginning of the year			1,613		1,438		1,614
Proceeds from borrowings			424		308		188
Payment of borrowings			(191)		(143)		(336)
Accrued interest			304		172		137
Payment of interests			(280)		(162)		(140)
Repurchase of CB			(6)		(28)		(3)
Result from exchange of CB			-		14		-
Result from repurchase of CB			(1)		(6)		-
Increases for incorporation			-		89		-
Foreign currency exchange difference			(356)		(80)		(22)
Decrease for subsidiaries sales			(80)		-		-
Borrowing costs capitalized in property, plant and equipment			21		11		-
At the end of the year			1,448		1,613		1,438

NOTE 12: (Continuation)

12.5.2 Details of borrowings:

Type of instrument

Company

Currency

Residual value

Interest

Rate

Expiration

Book value as of 12.31.2023

Corporate bonds (1)

Class 17 CB

PAMPA

$

5,980

Fixed

Badlar + 2%

May-24

9

Class 15 CB

PAMPA

$

18,264

Variable

Badlar + 0%

Jul-24

29

Class 18 CB

PAMPA

US$

72

Fixed

5.00%

Sep-25

73

Class 16 CB

PAMPA

US$

56

Fixed

4.99%

Nov-25

56

Class 9 CB

PAMPA

US$

179

Fixed

9.50%

Dec-26

184

Class 1 CB

PAMPA

US$

597

Fixed

7.50%

Jan-27

611

Class 13 CB

PAMPA

US$

98

Fixed

0.00%

Dec-27

96

Class 3 CB

PAMPA

US$

293

Fixed

9.13%

Apr-29

292

1,350

Financial loans(2)(3)

PAMPA

US$

8

Variable

SOFR 6M + 4,21%

Nov-24

8

PAMPA

$

3,000

Variable

Between 80% and 110%

Between Apr-24 and Jun-24

5

13

Other financial loans(4)

PAMPA

US$

22

Variable

SOFR + 0,35%

Jul-24

23

PAMPA

US$

12

Variable

SOFR + 0%

Agu-24

12

PAMPA

US$

14

Fixed

Between 13% and 16%

Between Jan-24 and Jun-24

14

PAMPA

CNY

37

Fixed

Between 12% and 12.50%

Between Mar-24 and Nov-24

5

54

Bank overdrafts(2)

PAMPA

$

23,140

Fixed

Between79.00% and 81,00%

Between Jan-24 and Apr-24

31

31

1,448

(1)	Net of repurchases for a face value of US$ 113.7 million for 2026 CB, US$ 153.0 million of 2027 CB, and US$ 7.5 million for 2029 CB.

(2)

During the fiscal year ended December 31, 2023, the Company took out short-term bank loans with local financial institutions, net of cancellations, for $ 16,535 million and import financing for CNY 37 million. Additionally, it took out import financing, net, for US$ 6.2 million. Post-closing, the Company took out net import financing for US$1 million and cancelled net bank debt for $100 million.

(3)

Regarding the FINNVERA credit facility and due to the discontinuation of the Libor benchmark interest rate as from July 2023, on September 5, 2023, Pampa and CACIB (Credit Agricole Corporate & Investment Bank) entered into an amendment to the credit facility replacing the Libor rate with the Term SOFR rate for debt services after November 2023. In this same line, the interest rate hedge agreement associated with the credit facility was also amended.

(4)	During the fiscal year ended December 31, 2023, the Company received disbursements in the amount of US$ 2.0 million under the credit facilities taken out with BNP Paribas S.A. in 2020.

NOTE 12: (Continuation)

Type of instrument

Company

Currency

Residual value

Interest

Rate

Expiration

Book value as of 12.31.2022

Corporate bonds (1)

T Series CB

PAMPA

US$

93

Fixed

7.38%

Jul-23

95

Class 8 CB

PAMPA

$

3,107

Variable

Badlar + 2%

Jul-23

20

Class 11 CB

PAMPA

$

21,655

Variable

Badlar + 0%

Jan-24

140

Class 9 CB

PAMPA

US$

102

Fixed

9.50%

Dec-26

184

Class 1 CB

PAMPA

US$

501

Fixed

7.50%

Jan-27

616

Class 13 CB

PAMPA

US$

49

Fixed

0.00%

Dec-27

48

Class 3 CB

PAMPA

US$

285

Fixed

9.13%

Apr-29

292

1,395

Financial loans(2)

PAMPA

US$

15

Variable

Libor + 4.21%

Nov-24

16

GW

US$

83

Variable

Libor + 5.75%

Sep-26

85

101

Other financial loans(3)

PAMPA

US$

22

Variable

SOFR + 0.35%

Jul-23

23

PAMPA

US$

8

Fixed

Between 9.50% and 14.50%

Between Jan-23 and May-23

8

PAMPA

US$

27

Variable

SOFR + 0%

Agu-24

27

58

Bank overdrafts (3)

PAMPA

$

10,065

Fixed

Between 54% and 54.50%

Jan-23

59

59

1,613

(1)	Net of the following face value repurchases: US$ 113.7 million of ON 2026, US$ 146.2 million of ON 2027 and US$ 7.5 million of ON 2029.

(2)

During the the fiscal year ended December 31, 2022, the Company took on new short-term financing with domestic financial entities, net of cancellations, for a total $ 8,618 million and import prefinancing for US$ 7.6 million. Additionally, the Company repaid at maturity two principal installments for the credit facility sponsored by FINNVERA in the amount of US$ 7.7 million and US$ 10.4 million corresponding to the credit facility subscribed between IDB Invest and Greenwind, a Company that is consolidated since acquisition of an additional 50% interest in August 2022.

(3)

During the fiscal year ended December 31, 2022, the Company received disbursements in the amount of US$ 1.3 million under the credit facilities taken out with BNP Paribas S.A. in 2020. After the fiscal year closing, the Company repaid short-term bank loans with local financial entities for $ 10,065 million and import prefinancing for US$ 0.7 million.

NOTE 12: (Continuation)

12.5.3 Global Program of CB

On September 30, 2021, the Company's General Ordinary and Extraordinary Shareholders' Meeting resolved to approve the creation of a new global corporate bonds program for an amount of up to US$ 2,000 million or its equivalent in other currencies or units of value, in the form of simple corporate bonds non-convertible into shares and/or corporate bonds convertible into shares, to renew the program expired on December 29, 2021. The public offering was authorized by the CNV on December 9, 2021.

12.5.4 Issuance of CB Class 8, 11, 13, 15, 16, 17, 18 and 19

On January 18, 2022, the Company issued Class 8 CB in the amount of $ 3,107 million at a Badlar rate + 2%, maturing in 18 months. This was the first green bond issued by Pampa and CB issue´s proceeds were allocated to finance the expansion of PEPE VI (see Note 18.1).

On July 15, 2022, the Company issued Class 11 CB for $ 12,690 million, accruing interest at a variable Badlar rate plus an annual 0% spread and maturing on January 15, 2024.

Additionally, on August 8, 2022 the Company reopened Class 11 CB for $ 8,963.9 million at an issuance price of 1.0305. The total face value of outstanding Class 11 CB amounted to $ 21,654.6 million.

On December 13, 2022, the Company issued Clase 13 US$-link CB for US$ 49.9 million at a fixed interest rate of 0% and maturing on December 2027.

On January 11, 2023, the Company issued Class 15 CB for $ 10,379 million accruing interest at a variable Badlar rate plus an annual 2% spread and maturing on July 11, 2024.

Subsequently, on March 6, 2023, the Company reopened Class 13 and Class 15 CB for US$ 48.2 million and $ 7,885 million, respectively.

On May 4, 2023, the Company issued Class 16 CB for US$ 55.7 million, with a fixed 4.99% interest rate and maturing on November 4, 2025, as well as Class 17 CB for $ 5,980 million accruing interest at a variable Badlar rate plus an annual 2% spread and maturing on May 4, 2024. Class 17 CB are the second green bond issued by Pampa, and proceeds will be destined for financing PEPE VI (see Note 17.1).

The issuance of green bonds reflects the commitment to financing projects with a positive impact on the environment and to diversifying the country's energy generation matrix. The issuance of Class 8 and Class 17 CB was recognized by Fix Ratings, an affiliate of Fitch Ratings, with the rating of Green Bond (BV1), the best possible grade, since it is aligned with the four main components of ICMA (International Capital Market Association) Green Bond Principles (GBP), and was made in observance of the "Guidelines for the Issuance of Social, Green and Sustainable Bonds in Argentina" of the CNV Rules, the provisions of BYMA's Social, Green and Sustainable Guide and the BYMA Rules, making up BYMA's Social, Green and Sustainable Bonds Panel.

On July 18, 2023, the Company repaid at maturity the total outstanding amount of Class 8 CB for $ 2,283 million.

NOTE 12: (Continuation)

On September 8, 2023, the Company issued Class 18 CB for US$ 72.1 million, accruing interest at a fixed 5% rate and maturing on September 8, 2025.

Finally, on December 21, 2023, the Company early redeemed Class 11 CB for an amount equivalent to the unpaid principal and accrued interest of $ 26,279.5 million.

Post-closing, Pampa redeemed all Class 17 CB, for a total amount of $ 5,980 million. Additionally, on February 29, 2024, the Company issued Class 19 CB for $ 17,131 million accruing interest at a variable Badlar rate plus an annual -1% spread and maturing on February 28, 2025.

12.5.6 Series T CB Exchange Offer

On June 16, 2022, the Company launched an exchange offer for holders of Series T CB maturing in 2023 originally issued by Petrobras Argentina S.A. (currently merged with the la Company) dated July 21, 2016 for a face value of US$ 500 million, under its Global Program authorized pursuant to CNV Resolution No. 17,162 dated August 15, 2013.

Once the exchange offer expired on July 29, 2022, the information and exchange agent informed the Company that US$ 193.8 million and US$ 213.3 million, representing 38.8% and 42.7% of the Series T CB' outstanding principal, had been validly tendered for exchange under Option A and Option B, respectively, totaling a US$ 407.1 million participation and representing approximately 81.4% of the outstanding Series T CB' capital amount.

Consequently, on August 8, 2022, after meeting the conditions established in the exchange offer documents, Pampa issued Class 9 CB for a face value of US$ 292.8 million, accruing interest at an annual fixed 9.5% rate and maturing on December 8, 2026, payable in three consecutive annual installments starting in 2024, and paid US$ 122.1 million in cash. For each US$ 1,000 of Series T CB's capital amount validly tendered and accepted for exchange, eligible holders received, together with the payment of interest accrued on Series T CB up to the settlement date: (i) Option A: approximately US$ 377.2 in Class 9 CB and US$ 630.2 in cash; and (ii) Option B: US$ 1,030 in Class 9 CB.

As a result of the debt swap, the Company disclosed losses for $ 1,997 million (US$ 14 million) under "Other financial results" to reflect the change in the payment estimates discounted at Series T CB's original effective interest rate, since they were not deemed substantially different from the issuance conditions for Class 9 CB, in accordance with IFRS´ Accounting Standards.

Later, on May 5, 2023, the Company announced the redemption of all Series T CB maturing on July 21, 2023, which outstanding balance amounted to US$ 92.9 million.

The redemption took place on June 8, 2023 at a redemption price equivalent to 100% of the outstanding capital amount, plus interest accrued and unpaid as of the redemption date, plus additional amounts under the Series T CB's trust agreement.

NOTE 12: (Continuation)

12.6Trade and other payables

	Note		12.31.2023		12.31.2022
Non-Current
Compensation agreements			28		10
Finance leases liability			14		10
Contractual penalty debt			4		-
Other			-		1
Other payables			46		21
Total non-current			46		21
Current
Suppliers			186		198
Customer advances			9		3
Related parties	16		15		14
Trade payables			210		215
Compensation agreements			11		12
Liability for acquisition of companies			8		46
Finance leases liability			4		2
Investment plan readjustment liability			-		5
Contractual penalty debt			2		-
Debtors			3		-
Other			-		1
Other payables			28		66
Total current			238		281

Due to the short-term nature of the trade payables and other payables, their carrying amount is considered to be the same as their fair value. For most other non-current debts, fair values are also not significantly different from their book values.

NOTE 12: (Continuation)

12.7Financial instruments by category

The following table presents financial instruments by category:

As of December 31, 2023		Financial assets/liabilities at amortized cost		Financial assets/liabilities at fair value through profit and loss		Subtotal financial assets/liabilities		Non financial assets/liabilities		Total
Assets
Trade receivables and other receivables		279		7		286		28		314
Financial assets at amortized cost
Term deposit		101		-		101		-		101
Notes receivable		4		-		4		-		4
Financial assets at fair value through profit and loss
Government securities		-		389		389		-		389
Corporate bonds		-		79		79		-		79
Shares		-		123		123		-		123
Mutual funds		-		3		3		-		3
Cash and cash equivalents		31		140		171		-		171
Total		415		741		1,156		28		1,184
Liabilities
Trade and other liabilities		275		-		275		9		284
Borrowings		1,448		-		1,448		-		1,448
Total		1,723		-		1,723		9		1,732
As of December 31, 2022		Financial assets/liabilities at amortized cost		Financial assets/liabilities at fair value through profit and loss		Subtotal financial assets/liabilities		Non financial assets/liabilities		Total
Assets
Trade receivables and other receivables		437		22		459		31		490
Financial assets at amortized cost
Term deposit		101		-		101		-		101
Notes receivable		9		-		9		-		9
Financial assets at fair value through profit and loss
Government securities		-		279		279		-		279
Corporate bonds		-		116		116		-		116
Shares		-		187		187		-		187
Mutual funds		-		31		31		-		31
Cash and cash equivalents		11		95		106		-		106
Total		558		730		1,288		31		1,319
Liabilities
Trade and other liabilities		298		-		298		4		302
Borrowings		1,613		-		1,613		-		1,613
Derivative financial instruments		-		2		2		-		2
Total		1,911		2		1,913		4		1,917

The categories of financial instruments have been determined according to IFRS 9.

NOTE 12: (Continuation)

The income, expenses, gains and losses derived from each of the financial instrument categories are indicated below:

As of December 31, 2023		Financial assets/liabilities at amortized cost		Financial assets/liabilities at fair value through profit and loss		Subtotal financial assets/liabilities		Non Financial assets/ liabilities		Total
Interest income		5		-		5		-		5
Interest expenses		(307)		-		(307)		(49)		(356)
Foreign currency exchange difference, net		(1,035)		(560)		(1,595)		1,718		123
Changes in the fair value of financial instruments		-		444		444		-		444
Result from present value measurement		(1)		-		(1)		(9)		(10)
Other financial results		(7)		-		(7)		-		(7)
Total		(1,345)		(116)		(1,461)		1,660		199
As of December 31, 2022		Financial assets/liabilities at amortized cost		Financial assets/liabilities at fair value through profit and loss		Subtotal financial assets/liabilities		Non Financial assets/ liabilities		Total
Interest income		5		-		5		-		5
Interest expenses		(175)		-		(175)		(41)		(216)
Foreign currency exchange difference, net		16		(85)		(69)		149		80
Changes in the fair value of financial instruments		-		110		110		-		110
Result from present value measurement		(1)		-		(1)		(13)		(14)
Other financial results		(15)		-		(15)		-		(15)
Total		(170)		25		(145)		95		(50)
As of December 31, 2021		Financial assets/liabilities at amortized cost		Financial assets/liabilities at fair value through profit and loss		Subtotal financial assets/liabilities		Non Financial assets/ liabilities		Total
Interest income		10		-		10		-		10
Interest expenses		(138)		-		(138)		(40)		(178)
Foreign currency exchange difference, net		(11)		(19)		(30)		33		3
Changes in the fair value of financial instruments		-		(15)		(15)		-		(15)
Result from present value measurement		2		-		2		(3)		(1)
Other financial results		(4)		-		(4)		(4)		(8)
Total		(141)		(34)		(175)		(14)		(189)

NOTE 12: (Continuation)

12.8Fair value of financial Instruments

The Company classifies the fair value measurements of financial instruments using a fair value hierarchy, which reflects the relevance of the variables used to perform those measurements. The fair value hierarchy has the following levels:

-	Level 1: quoted prices (not adjusted) for identical assets or liabilities in active markets.

-	Level 2: data different from the quoted prices included in Level 1 observable for the asset or liability, either directly (i.e. prices) or indirectly (i.e. derived from prices).

-	Level 3: Asset or liability data based on information that cannot be observed in the market (i.e., unobservable data).

The following table shows the Company's financial assets and liabilities measured at fair value as of December 31, 2023 and 2022:

As of December 31, 2023		Level 1		Level 2		Level 3		Total
Assets
Financial assets at fair value through profit and losss
Government securities		389		-		-		389
Corporate bonds		79		-		-		79
Mutual funds		3		-		-		3
Shares		88		-		35		123
Cash and cash equivalents
Mutual funds		140		-		-		140
Other receivables
Guarantee deposits on derivative financial instruments		7		-		-		7
Total assets		706		-		35		741
As of December 31, 2022		Level 1		Level 2		Level 3		Total
Assets
Financial assets at fair value through profit and losss
Government securities		279		-		-		279
Corporate bonds		116		-		-		116
Mutual funds		31		-		-		31
Shares		160		-		27		187
Cash and cash equivalents				-		-
Mutual funds		95		-		-		95
Other receivables		22		-		-		22
Total assets		703		-		27		730
Liabilities
Derivative financial instruments		-		2		-		2
Total liabilities		-		2		-		2

NOTE 12: (Continuation)

The value of the financial instruments negotiated in active markets is based on the market quoted prices as of the date of these Consolidated Financial Statements. A market is considered active when the quoted prices are regularly available through a stock exchange, broker, sector-specific institution or regulatory body, and those prices reflect regular and current market transactions between parties that act in conditions of mutual independence. The market quotation price used for the financial assets held by the Company is the current offer price. These instruments are included in Level 1.

The fair value of financial instruments that are not negotiated in active markets is determined using valuation techniques. These valuation techniques maximize the use of market observable information, when available, and rely as little as possible on specific estimates of the Company. If all significant variables to establish the fair value of a financial instrument can be observed, the instrument is included in Level 2.

If one or more variables used to determine the fair value cannot be observed in the market, the financial instrument is included in Level 3.

The techniques used for the measurement of assets at fair value with changes in profit (loss), classified as Level 2 and 3, are detailed below:

-	Derivative Financial Instruments: calculated from variations between market prices at the closing date of the year, and the amount at the time of the contract.

-

Shares: it was determined using the income-based approach through the "Indirect Cash Flow" method, that is, the net present value of expected future cash flows, mainly through the collection of dividends taking into consideration the direct equity interest of 2.84% and 3.19%, and the additional equity interest of 2.18% and 2.46% through HIDISA and HINISA, in TJSM and TMB, respectively, resulting from the Federal Government's restructuring of assets in the energy sector. This restructuring resulted in TMB's and TJSM's share transfer from the Federal Government to ENARSA, considering 16.6% and 16.4% discount rate as of December, 31 2023 and 2022, respectively. The key assumptions were prepared based on estimates on the future behavior of certain sensitive variables, including: (i) the dividend distribution policy; (ii) reference prices for energy sold in the spot market; (iii) projections of the availability and dispatch of power plants; (iv) the evolution of structural costs and expenses; (v) macroeconomic variables such as inflation and exchange rates, etc. The Company recognised earnings for US$ 7.2 million and losses for US$ 1.7 million as a result of changes in the fair value of financial instruments classified as level 3, under the item "Other financial results" of the Consolidated Statement of Comprehensive Income, as of December, 31 2023 and 2022, respectively. Current values may substantially differ from projections, mainly on account of: i) the timeliness and magnitude of the distribution of dividends, ii) the timeliness and magnitude of energy price updates, and/or iii) the evolution of costs. The Company estimates that any sensitivity analysis that considers changes in any of the estimates taken individually may lead to distorting conclusions, generating an adverse effect on the Company's results.

NOTE 13: EQUITY COMPONENTS

13.1 Share capital

As of December 31, 2023, the share capital amounts to $ 1,364 million, including approximately $ 4 million treasury shares.

13.1.1 Share buyback programs

Taking into consideration the market volatility and the persisting divergence between the Company's share price and the economic reality its assets currently or potentially have, which is detrimental to the interests of its shareholders, and considering the Company's history of strong cash position and fund availability, the Board of Directors has implemented several share buyback programs, considering in each case that treasury shares may not exceed the 10% capital stock capitalization.

During 2021, the Company directly and indirectly acquired 2.7 million own ADRs for a value of US$ 38.7 million, and the repurchased shares canceled in full.

During 2022, the Company indirectly acquired 0.9 million own ADRs for a value of US$ 18.2 million to an average price of US$ 20,3 per ADR, which were canceled in full.

During 2023, the Company did not acquired own shares.

13.1.2 Stock Compensation Plan

As of December, 31 2023, 4 million remained in treasury to be delivered to employees under such plan (see Note 4.17).

13.1.3 Capital reductions

During 2021, the capital stock reduction approved by the Company's General Ordinary and Extraordinary Shareholders' Meeting held on April 29 and September 30, which provided for the cancellation of 56.6 million shares and 12.5 million shares, respectively. These reductions are registered in the Public Registry.

On April 27, 2022, General Ordinary and Extraordinary Shareholders' Meeting resolved to reduce the Company's capital stock by canceling 2.8 million shares which took place during October 2022. This reduction was registered with the Public Registry on September 14, 2022.

On April 26, 2023, the Company's General Ordinary and Extraordinary Shareholders' Meeting resolved to reduce the capital stock through the cancellation of 20.1 million shares, the reduction taking effect in May 2023. This reduction was registered with the Public Registry on June 28, 2023.

NOTE 13: (Continuation)

13.2 Earnings per share

Basic earnings per share are calculated by dividing the result attributable to the Company's equity interest holders by the weighted average of outstanding common shares during the year. Diluted earnings per share are calculated by adjusting the weighted average of outstanding common shares to reflect the conversion of all dilutive potential common shares.

Potential common shares will be deemed dilutive only when their conversion into common shares may reduce the earnings per share or increase losses per share of the continuing business. Potential common shares will be deemed anti-dilutive when their conversion into common shares may result in an increase in the earnings per share or a decrease in the losses per share of the continuing operations.

The calculation of diluted earnings per share does not entail a conversion, the exercise or another issuance of shares which may have an anti-dilutive effect on the losses per share, or where the option exercise price is higher than the average price of ordinary shares during the period, no dilutive effect is recorded, being the diluted earnings per share equal to the basic. As of December 31, 2023, 2022 and 2021, the Company does not hold any significant potential dilutive shares, therefore there are no differences with the basic earning per share.

		12.31.2023		12.31.2022		12.31.2021
Earning for continuing operations attributable to equity holders of the Company		302		456		312
Weighted average amount of outstanding shares		1,366		1,381		1,405
Basic and diluted earnings per share from continued operations		0.22		0.33		0.22
Loss for discontinued operations attributable to equity holders of the Company		-		-		(39)
Weighted average amount of outstanding shares		1,366		1,381		1,405
Basic and diluted loss per share from discontinued operations		-		-		(0.03)
Earning attributable to equity holders of the Company		302		456		273
Weighted average amount of outstanding shares		1,366		1,381		1,405
Basic and diluted earning per share		0.22		0.33		0.19

NOTE 13: (Continuation)

13.3 Profit distributions

Dividends distributed to individuals, undivided estates or beneficiaries residing abroad, derived from profits generated during fiscal years beginning on or January 1, 2018 are subject to a 7% withholding tax (see Note 2.6.1.2). The distribution of dividends is made based on the Company's Stand-Alone Financial Statements which are presented in pesos, the legal currency in Argentina, pursuant to regulatory requirements.

NOTE 14: STATEMENT OF CASH FLOWS' COMPLEMENTARY INFORMATION

14.1 Adjustments to reconcile net profit to cash flows generated by operating activities

	Note		12.31.2023		12.31.2022		12.31.2021
Income tax	10.6		318		124		77
Accrued interest			283		185		141
Depreciations and amortizations	9 and 10.2		267		212		205
Share of profit of joint ventures and associates	5.3.2		2		(105)		(100)
Profit from sale/acquisition of companies´ interest			(9)		-		(17)
Results for property, plant and equipment sale and derecognition	10.4		1		(2)		(1)
Result for intangible assets sale	10.4		-		(2)		(2)
Impairment of property, plant and equipment, intangible assets and inventories	11.1, 11.2 and 11.4		39		38		4
(Impairment) Recovery of impairment of financial assets			-		4		(1)
Result from present value measurement	10.5		10		14		1
Changes in the fair value of financial instruments			(392)		(94)		24
Exchange differences, net			(190)		(85)		(3)
Result from exchange of CB	10.5		-		14		-
Result from repurchase of CB	10.5		(1)		(6)		-
Readjustment of investment plan	10.4		-		9		-
Costs of concessions agreements completion	10.4		5		-		-
Contractual indemnity	10.4		(7)		-		-
Contractual penalty	10.4		7		-		-
Compensation for arbitration award	10.4		-		(37)		-
Provision for contingecies, net	10.4		8		4		3
Provision for environmental remediation	10.4		4		-		15
Fair value of consortiums' previous interest	10.4		(7)		-		-
Impairment of other receivables	10.4		5		-		-
Ecuador's transactional agreement	10.4		5		-		-
Expenses recovery	10.4		(8)		-		-
Accrual of defined benefit plans	9 and 10.2		26		14		11
Compensation agreements	10.2		37		19		2
Derecognition of unproductive wells	10.3		7		-		-
Other			(4)		(4)		3
Adjustments to reconcile net profit to cash flows from operating activities			406		302		362

NOTE 14: (Continuation)

14.2 Changes in operating assets and liabilities

			12.31.2023		12.31.2022		12.31.2021
Increase in trade receivables and other receivables			(151)		(233)		(41)
Increase in inventories			(35)		(21)		(40)
Increase in trade payables and other payables			17		70		43
Increase in salaries and social security payables			20		15		8
Defined benefit plans payments			(3)		(3)		(2)
Increase (Decrease) in tax liabilities			27		41		(2)
Decrease in provisions			(7)		(1)		(3)
Income tax payment			-		(2)		(13)
Payments for derivative financial instruments, net			(4)		(6)		(12)
Changes in operating assets and liabilities			(136)		(140)		(62)

14.3 Significant non-cash transactions

		12.31.2023		12.31.2022		12.31.2021
Acquisition of property, plant and equipment through an increase in trade payables		(82)		(75)		(51)
Borrowing costs capitalized in property, plant and equipment		(21)		(11)		-
Increase of property, plant and equipment through exchange of assets		(25)		-		-
Acquisition of subsidiary by delivering financial assets at fair value through profit and loss		-		(35)		-
Receivables from sales of companies pending collection		-		-		40
Receivables for acquisition of subsidiary		-		7		-
Increase in investments in associates through a decrease in other receivables		-		-		(20)
Increase in right-of-use assets through an increase in other liabilities		(13)		(1)		(7)
Dividends pending collection		-		-		2
Decrease in asset retirement obligation and wind turbines decommision through property, plant and equipment		(5)		(1)		(1)
Decrease in associate's equity interest through increase in other receivables		-		6		-

NOTE 15: CONTINGENT LIABILITIES AND ASSETS

We hereinafter detail the nature of significant proceedings as of December 31, 2023, not considered as probable by the Company based on the opinion of the Company's internal and external counselors.

15.1 Labor Claim - Compensatory Plan

The Company faces several legal proceedings associated with the Defined Benefit Plan "Compensatory Plan" (see Note 11.8). We hereinafter describe the nature of currently pending labor claims :

-

Claims on considering that the index (CPI) used to update the plan benefits is ineffective to keep their "constant value". In two of the causes, the Company obtained a favorable judgment, which has been appealed by the plaintiff. On the other hand, the Company received an adverse judgment in a claim, consequently, the Company has filed an appeal before the applicable Chamber.

-

Claims on an alleged underfunding of the plan upon the elimination of the Company's contributions based on earnings. The Company obtained a favorable first-instance judgment. The plaintiff filed an appeal, which was sustained by the Commercial Chamber. Against said pronouncement, the Company filed a Federal Extraordinary Appeal before the CSJN, which was disallowed by the Appeals Chamber. Consequently, the Company filed a petition in error before the CSJN and an appeal on the grounds of unconstitutionality before the Supreme Court of Justice of the Autonomous City of Buenos Aires, this Court requested the Chamber to refer back the proceedings and ordered the hearing of the unconstitutionality appeal the Chamber had dismissed. In view of the Chamber's dismissal, the file was sent to the CSJN, which will settle the dispute over jurisdiction.

15.2 Tax claim

-	Tax on Liquid Fuels and Natural Gas:

The AFIP filed a claim in the amount of $ 54 million against the Company for an alleged omission in the payment of Taxes on Liquid Fuels and Natural Gas during fiscal periods January 2006 through August 2011, plus compensatory interest and a penalty of $ 38 million for such omission. The tax entity supports its claim on the allegation that the tax benefit granted to sales to areas declared exempt by the tax law has been misappropriated. The proceeding is currently being heard before the Federal Tax Court, and the evidentiary period has been completed.

NOTE 15: (Continuation)

15.3 Environmental claims

-

The Association of Land Owners of Patagonia (ASSUPA) has brought a complaint for an indefinite amount against the Company and other companies seeking the restoration of the environment to the state prior to the exploration, exploitation, production, storage and transportation of hydrocarbon works conducted by the plaintiffs and the prevention of alleged future environmental impacts on certain areas in the Austral Basin. The National Government and the Provinces of Santa Cruz and Tierra del Fuego have been summoned as third parties. The proceeding is at the complaint answer stage.

-

ASSUPA has instituted a complaint before the CSJN against 10 companies, including the Company. The National Government and the Provinces of Buenos Aires, La Pampa, Mendoza, Neuquén and Río Negro have been summoned as third parties. The main claim seeks that the plaintiffs should be ordered to redress the alleged environmental damage caused by the hydrocarbon activity developed in the Neuquina Basin and to set up the environmental restoration fund provided for by section 22 of the General Environmental Law. Subsidiarily, and in case restoration is not possible, it seeks the redress of the allegedly sustained collective damages for an amount estimated at US$ 547 million based on a United Nations Development Program report. The proceeding is in the complaint answer stage.

-

Beatriz Mendoza and other 16 plaintiffs brought a complaint before the CSJN against the National Government, the Province of Buenos Aires, the Government of the Autonomous City of Buenos Aires and 44 companies, including the Company, conducting industrial activities along the Matanza-Riachuelo River Basin. The plaintiffs seek compensation for alleged damages sustained as a result of an alleged environmental impact, its cessation, the environmental recomposition and redress, for an estimated amount of US$ 500 million for the financing of the Matanza-Riachuelo River Basin Environmental Management Plan aiming at the restoration of the basin. The Company's pecuniary liability would be associated with just two of its assets adjacent to the basin (one of them no longer under its operation). Regarding the other assets along the basin that were previously operated by it, the Company has sufficient indemnity granted by the facilities' assignee company.

-

Inertis S.A. has filed a complaint against the Company for alleged damage to the environment in a lot owned by this company as a result of the activities conducted by the Dock Sud Plant seeking the redress of alleged damages for a nominal amount estimated at $ 1 million and US$ 1 million, or the difference between the value of the allegedly affected lot and its valuation. The proceeding is in the evidentiary stage completed.

NOTE 15: (Continuation)

-

Fundación SurfRider Argentina has requested the performance of preliminary proceedings on account of alleged indications of environmental damage in the City of Mar del Plata. The plaintiff seeks the recomposition of the alleged environmental damage having collective impact, or the compensation for the alleged damages caused by all companies owning gas stations in the coastal area of the City of Mar del Plata for an alleged fuel leakage from gas stations' underground storage tanks into the water, soil and marine system. The Foundation estimates damages in the amount of $ 200 million. The parties agreed on a stay of the procedural time limits to evaluate the possibility of reaching an agreement with some co-defendants. Subsequently, the partial agreement reached between the plaintiff and some co-defendants was ratified. On its part, the Company has requested to be severed from the proceeding as it does not currently own any service station. However, it should be noted that some service station owners (which have sued the Company), have submitted agreements entered into with the plaintiff for their ratification under the proceeding. Some of them have already been ratified -and the plaintiff was deemed to have partially waived the action and rights against the owners of these service stations and also against the Company regarding them-, whereas others are in the ratification stage.

-

Some neighbors of the Dock Sud area brought a complaint against 14 oil companies, including the Company, petrochemical companies and waste incineration plants located in the Dock Sud Petrochemical Complex for an alleged damage to the environment and alleged individual damage to their goods, health and morale. The CSJN determined it had jurisdiction over the environmental issue and maintained the civil and commercial jurisdiction regarding the compensation for the alleged damages. The First-Instance Civil and Commercial Court opened the evidentiary stage.

-

A neighbor of the Province of Salta owning a lot where a joint venture made up of the plaintiffs (the Company and other companies) conducted hydrocarbon activities seeks environmental protection and restoration for alleged damage caused by hydrocarbon prospecting, exploration and/or exploitation activities or, alternatively, a compensation in case such environmental restoration is not possible. The Province of Salta has been summoned as a co-defendant. The proceeding is in the complaint answer stage and the Court of Justice of Salta declared that the First-Instance Administrative Litigation Court has jurisdiction over the claim.

-

Owners of a lot in the town of Garín, Province of Buenos Aires, seek the performance of preliminary proceedings for alleged indications of damage to the environment in their place of residence which would result from an alleged leakage from the adjacent gas station under the Company's branding. Although the Company has filed a motion for constructive abandonment of the proceeding, the plaintiff withdrew from the proceeding, and therefore the judge in charge declared it terminated.

-

Neighbors of the Province of Neuquén brought a proceeding against the Company for alleged environmental damage resulting from the hydrocarbon exploration, exploitation, transportation and well abandonment activities in which that plaintiff has been taking part. Should this not be feasible, they claim a compensation for alleged damages to support the Environmental Restoration Fund. Additionally, they request the redress of alleged moral damages to be allocated to the Environmental Restoration Fund. The presence of all involved parties has been properly verified, and the lawsuit has been referred to the administrative litigation jurisdiction.

NOTE 15: (Continuation)

-

Plaintiff Martinez Lidia and other three plaintiffs claim financial compensation for alleged damage to their health and property caused by the alleged environmental affectation sustained as a result of living next to Puerto General San Martin petrochemical plant (Rosario-Santa Fe). The Court issued an order to furnish additional evidence and, consequently, the proceeding was consolidated with the lawsuit filed against the Company by other neighbors of the Santa Fe Plant. This last proceeding is in the evidentiary stage.

-

A neighbor of the Province of Buenos Aires brought a complaint against the Company seeking the removal of three fuel storage tanks and pumps and the remediation and restoration of the soils where such tanks are located on account of an alleged environmental affectation. The proceeding is in the evidentiary stage completed.

-	Neighbors of the Province of Santa Fe have brought a complaint against the Company for alleged environmental damage. The Company obtained a favorable judgment, which has been appealed by the plaintiff.

15.4 Civil and Commercial Claims

-

The "Consumidores Financieros Asociación Civil Para Su Defensa" claim the nominal amount of US$ 3,650 million as compensation for damages, Pampa, Petrolera Pampa S.A. and certain Pampa directors in office during 2016 being co-plaintiffs together with Petroleo Brasileiro S.A. A complaint has been brought against Petrobras Brasil for the depreciation of the share quotation value as a result of the "lava jato operation" and the so-called "Petrolao", and the plaintiffs claim Pampa, Petrolera Pampa S.A. and the directors' joint and several liability alleging the acquisition of indirect control in Petrobras Argentina S.A. may have thwarted the enforcement of a possible judgment favorable to the plaintiff (for up to the amount of the price paid by Pampa for the acquisition of control over Petrobras Argentina S.A.). The plaintiff appealed the Arbitration Court's decision declaring the dismissal of the main claim upon the failure to pay the arbitration fee. The Chamber of Appeals in Commercial Matters upheld the filed extraordinary appeal. On its part, Petróleo Brasileiro S.A. filed an appearance, requested that the lack of substance of the filed appeal should be declared, and subsidiarily answered it. The Company was served notice of the upholding of the motion made by the Chamber of Appeals in Commercial Matters and filed a presentation in this respect. Later, the CSJN declared the nullity of the Chamber of Appeals in Commercial Matters' decision upholding the extraordinary appeal and referred the court file back so that a new judgment should be rendered. The Chamber of Appeals in Commercial Matters rendered judgment dismissing the federal extraordinary appeal brought by this Association. The Association filed a petition in error against this decision, which is currently under analysis by the CSJN.

We hereinafter detail the nature of significant legal proceedings brought by the Company as of December 31, 2023 where the related inflows of economic benefits are estimated to be probable by the Company.

15.5 Administrative claims

-

CTLL (currently Pampa) filed an administrative litigation complaint against the Federal Government for contractual breach during the January 2016-March 2016 period. CTLL claims that CAMMESA's decision regarding the renewal and recognition of costs associated with natural gas supply agreements should be reversed and that, subsidiarily, sustained damages should be redressed. Later on, CTLL filed a new contentious administrative litigation complaint against the Federal Government for contractual breach during the April 2016-October 2018 period. In the complaint for the January-March 2016 period, the closing of the evidentiary stage was suspended on account of the proceeding's link with the complaint subsequently field for the April 2016- October 2018 period, proceeding which is currently at the pleadings stage.

NOTE 15: (Continuation)

-

Upon the determination of the expiration of the Veta Escondida block concession granted by the Province of Neuquén, the Company filed a declaratory judgment action to achieve certainty under the original jurisdiction of the CSJN pursuant to section 322 of the Federal Code of Civil and Commercial Procedure. Both parties agreed to suspend the proceeding to pursue a private settlement, the rendering of judgment was requested and the CSJN has set a preliminary hearing, which was carried out. Currently, after the opinion rendered by the National Attorney General, the proceeding is pending judgment by the CSJN.

-

On March 31, 2021, the Company submitted a Preliminary Administrative Claim (RAP) against the National Ministry of Economy (MECON) to claim the owed amount, plus the applicable interest, assumed by the Federal Government during the term of validity of PEN Executive Order No. 1,053/18 on account of the exchange difference between the price of the gas purchased by gas distributors and that recognised in their final tariffs during the April 2018 - March 2019 period. On September 1, 2021 a request for an expedited procedure was filed. On September 1, 2021. a request for an expedited procedure was filed. On December 2, 2021, the Company filed a protective action (amparo) on the grounds of undue delay seeking that defendant should state its opinion in this respect. A judgment was rendered dismissing the amparo. The Company has filed an appeal against this decision, which was dismissed by the Chamber hearing the case. As MECON's term to state its position on the RAP has expired, the Company has brought a complaint against the Federal Government.

15.6 Civil and Commercial Claims

-

EcuadorTLC (currently Pampa Bloque 18), in its capacity as assignee of the Ecuadorian company Petromanabí S.A., filed an international arbitration proceeding against the Republic of Ecuador seeking the payment of 12% of the Settlement Value, the latter pursuant to the terms of the Hydrocarbon Exploration and Crude Oil Exploitation Participation Agreement in Block 18 entered into on December 19, 1995 and/or the Hollín Common Field Unified Exploitation Operating Agreement executed on August 7, 2002 -in both cases, as amended-. The arbitration is conducted according to the Arbitration Rules of the United Nations Commission on International Trade Law, the applicable law is Ecuadorian law, and the seat of arbitration is the City of Santiago de Chile. In 2021, the first stages of the international arbitration proceeding have already begun. As of the issuance of these Consolidated Financial Statements, the arbitration proceeding is ongoing.

-

The Company has instituted an international arbitration proceeding against High Luck Group Limited - Argentina branch as a result of certain breaches to the Participation Assignment Agreement and the Joint Operation Agreement for the Chirete Block entered into on April 1, 2015. On August 23, 2023, the Arbitration Court issued a Partial Award, court costs being payable by the defendant, declaring that High Luck had breached the above-mentioned Agreement, without this fact entitling the Company to exercise the reversal option stipulated therein. A new arbitration stage is currently underway pursuant to the schedule established by the Arbitration Court.

NOTE 16: RELATED PARTIES´ TRANSACTIONS

16.1 Balances with related parties

As of December 31, 2023		Trade receivables		Other receivables		Trade payables
	Current		Non-current		Current		Current
Associates and joint ventures
CTB		1		-		-		-
TGS		4		11		6		7
Other related parties
SACDE		-		-		-		8
Other		-		-		1		-
		5		11		7		15
As of December 31, 2022		Trade receivables		Other receivables		Trade payables
	Current		Non-current		Current		Current
Associates and joint ventures
TGS		5		17		6		7
Other related parties
SACDE		-		-		-		7
Other		-		-		1		-
		5		17		7		14

NOTE 16: (Continuation)

16.2 Operations with related parties

Operations for the year		Sales of goods and services (1)		Purchases of goods and services (2)		Fees for services (3)		Other operating expenses and income (4)
	2023		2022		2021		2023		2022		2021		2023		2022		2021		2023		2022		2021
Associates and joint ventures
CTB		2		2		2		-		-		-		-		-		-		-		-		-
Greenwind		-		-		1		-		-		-		-		-		-		-		-		-
Refinor		-		11		9		-		(11)		(6)		-		-		-		-		-		-
TGS		42		51		45		(53)		(53)		(43)		-		-		-		-		-		-
Other related parties
Fundación		-		-		-		-		-		-		-		-		-		(2)		(2)		(2)
SACDE		-		-		-		(65)		(203)		(48)		-		-		-		-		-		-
Salaverri, Dellatorre, Burgio & Wetzler		-		-		-		-		-		-		(1)		(1)		(1)		-		-		-
		44		64		57		(118)		(267)		(97)		(1)		(1)		(1)		(2)		(2)		(2)

(1)	Corresponds mainly to advisory services provided in the field of technical assistance and sales of gas and refined products.

(2)

Correspond to natural gas transportation services, purchases of refined products and other services imputed to cost of sales for US$ 53 million, US$ 191 million and US$ 50 million and infrastructure works contracted to SACDE imputed in property, plant and equipment for US$ 65 million, US$ 76 million and US$ 47 million, of which US$ 15 million, US$ 16 million and US$ 17 million correspond to fees and general expenses calculated on the costs incurred by SACDE and/or Pampa to carry out these for the years ended December 31, 2023, 2022 and 2021, respectively.

(3)	Disclosed within administrative expenses.

(4)	Corresponds mainly to donations.

Operations for the year		Finance income (1)		Dividends received		Payment of dividends
	2023		2022		2021		2023		2022		2021		2023		2022		2021
Associates and joint ventures
OCP		-		-		1		-		10		20		-		-		-
TGS		2		2		3		-		-		-		-		-		-
Other related parties
EMESA		-		-		-		-		-		-		(1)		-		(9)
		2		2		4		-		10		20		(1)		-		(9)

(1)	Corresponds mainly to financial leases and accrued interest on loans granted.

NOTE 16: (Continuation)

16.3 Key management personnel remuneration

During the years ended December 31, 2023 2022 and 2021, the total remuneration to executive directors accrued amounts to US$ 44 million (US$ 7 million for Directors' and Sindycs' fees and US$ 37 million in the accrual of Stock-based Compensation Plans and Compensation Agreements), US$ 26 million (US$ 7 million for Directors' and Sindycs' fees and US$ 19 million in the accrual of Stock-based Compensation Plans and Compensation Agreements), and US$ 7 million (US$ 6 million for Directors' and Sindycs' fees and US$ 1 million in the accrual of Stock-based Compensation Plans and Compensation Agreements), respectively.

NOTE 17: INVESTMENT COMMITMENTS

17.1 New generation projects

Under the National Government's call for the expansion of the generation offer, the Company participated in the following generation projects:

PEPE IV

In early 2022, works started for the expansion of PEPE III, inaugurated in 2019 and located in the town of Coronel Rosales, Province of Buenos Aires, which production is targeted at the large users segment.

The project mainly consisted of the staged mounting and installation of 18 additional wind turbines with an 81 MW capacity. The expansion's commissioning started on December 29, 2022, with the first 4 wind turbines, and ended on June 17, 2023 with the project's last 3 wind generators.

After completing the expansion works, PEPE III and PEPE IV jointly have 32 wind turbines with a 134.2 MW installed capacity.

PEPE VI

In February 2023, the Company started constructing Pampa Energía VI Wind Farm in Bahía Blanca, Province of Buenos Aires. The project will enable the installation of a 300 MW power capacity, in 3 stages, with an estimated US$ 500 million investment.

Stage 1 comprises the assembly and installation of 21 Vestas wind turbines, with their internal medium-voltage cable network, roads, a substation and a 500 KV line, which will add a 94.5 MW capacity with an approximate US$186 million investment; this stage is expected to be operational in mid-2024.

Stage 2 comprises the assembly and installation of 10 Vestas wind turbines that will add a 45 MW capacity with an approximate US$ 83 million investment; this stage is expected to be operational in the fourth quarter of 2024.

The energy produced by this wind park allows for reduced carbon emissions, and will be sold through the MATER to supply large companies in the country, in compliance with the Renewable Energy Law.

As of the issuance of these Consolidated Financial Statements, the work is 59% complete.

NOTE 17: (Continuation)

17.2 Investment commitment for the exploration and exploitation of hydrocarbons

On November 30, 2023, Executive Order No. 2,425/23 was published, declaring the completion of the Pilot Plan for the Sierra Chata block, consisting of the execution of 14 horizontal wells targeting the Vaca Muerta formation with a US$ 332 million investment.

As of the issuance of these Consolidated Financial Statements, the Company has committed investments until 2027 for an estimated total amount of US$ 217 million, including commitments associated with the participations detailed in Note 5.4.

NOTE 18: INCIDENTS AT THERMAL POWER PLANT

18.1 CTGEBA

On May 31, 2021, an incident occurred at the GEBATG03 (TG21) unit, part of CTGBS's Genelba Plus CC, causing damage to the unit's turbine. As a result of the incident, the CC generation capacity was reduced by approximately 50% (280 MW).

Jointly with the turbine manufacturer (SIEMENS), the Company performed the necessary works to disassemble and repair the failure, which were successfully completed in July 2021.

In the fourth quarter of 2023, the Company completed the necessary filings with the insurance companies, recording an expense recovery of US$ 8 million for the damages sustained as a result of the failure and the economic losses resulting from the breach of the availability commitments.

18.2 CTLL

On July 20, 2023, an incident occurred at CTLL's GT05, causing damage to the unit's turbine. As a result of the incident, the power generation capacity was reduced by approximately 105 MW.

The Company, together with the turbine manufacturer, General Electric, carried out the necessary works to repair the failure, which were completed in January 2024.

Moreover, the Company is making all necessary filings before the insurance companies to minimize economic losses resulting from the breach of the associated availability commitments.

NOTE 19: LEASES

19.1 Lessee

The Company leases a key part for thermal power plants operation for a 20-year term and has entered into certain oil services agreements (mainly gas compression services) which, considering their characteristics, contain the lease of the assets for the rendering of the services with terms ranging between 2 and 6 years.

The terms of the lease agreements are negotiated on an individual basis and comprise a broad range of terms and conditions.

NOTE 19: (Continuation)

The evolution of right-of-use assets and lease liabilities recognised as of December 31, 2023 and 2022 is disclosed below:

19.1.1 Right of use assets

			Original values
							Decrease
Type of good			At the beginning		Increase			At the end
Machinery and equipment			20		7		-		27
Advances to suppliers			-		6		-		6
Total at 12.31.2023			20		13		-		33
Total at 12.31.2022			20		1		(1)		20
			Amortization
Type of good			At the beginning		For the year		At the end
Machinery and equipment			(11)		(1)		(12)
Total at 12.31.2023			(11)		(1)		(12)
Total at 12.31.2022			(8)		(3)		(11)
			Net book values
Type of good			At 12.31.2023		At 12.31.2022
Machinery and equipment			15		9
Advances to suppliers			6
Total at 12.31.2023			21
Total at 12.31.2022					9

NOTE 19: (Continuation)

19.1.2 Lease liabilities

			12.31.2023		12.31.2022
At the beginning of the year			12		13
Increases			7		1
Result from measurement at present value (1)			2		2
Reversal of unused amounts			-		(1)
Payments			(3)		(3)
At the end of the year			18		12

(1)	Included in Other financial results.

As of December 31, 2023 and 2022, this liability is disclosed under Other current payables in the amount of US$ 4 million and US$ 2 million and Other non-current payables for US$ 14 million and US$ 10 million, respectively.

The following table includes an analysis of the Company lease liabilities, grouped according to their maturity dates. The amounts shown in the table are the contractual undiscounted cash flows:

			12.31.2023
Three months to one year			4
One to two years			2
Two to three years			3
Three to four years			3
Four to five years			3
More than five years			17
Total			32

19.1.3 Short-term or low value leases

As of December 31, 2023 and 2022, the Company has recognised administrative costs and expenses in the amount of US$ 6 million each year on account of lease payments associated with short-term leases.

NOTE 19: (Continuation)

19.2 Lessor

19.2.1 Financial leases

Corresponding to the financing granted to TGS for the sale of certain property, plant and equipment belonging to the Oil & Gas business segment. This agreement was entered into on August 11, 2016 and consists of the collection of 119 monthly consecutive installments of US$ 623 thousand, without considering taxes, and a purchase option for a like amount payable at the end of the 120 months of the contract life.

As of December 31, 2023 and 2022, this receivable is disclosed under Other current receivables in the amount of US$ 6 million both years, respectively and under Other non-current receivables for US$ 11 million and US$ 17 million, respectively.

The following table includes an analysis of the Company receivable, grouped according to its maturity dates. The amounts shown in the table are the contractual undiscounted cash flows:

			12.31.2023
Less than three months			2
Three months to one year			4
One to two years			7
Two to three years			4
Total			17

19.2.2 Operating leases

The Company has executed lease agreements to install commercial and administrative offices in Pampa Energía S.A.'s building, located in Maipú 1, Autonomous City of Buenos Aires, for three to five years terms.

Future minimum collections from operating leases as of December 31, 2023 are detailed below:

			12.31.2023
Three months to one year			1
One to two years			1
Total			2

Total income from operating leases for the fiscal year ended December 31, 2023 amounts to US$ 1 million.

NOTE 20: TERMINATION OF HYDROELECTRIC CONCESSIONS

As the hydroelectric concessions timely granted by the Federal Government and, in some cases, by the Provinces approach expiration, on March 10, 2022, SE Resolution No. 130/22 was published, creating a Concessioned Hydroelectric Exploitations Team ("ETAHC") to evaluate the status of the hydropower concessions under national jurisdiction, including HIDISA, HINISA, and HPPL.

This team will be presided over by the Secretary of Energy (or the person appointed by him) and coordinated by a person with proven experience in the field. It will also be made up of representatives of the SE, CAMMESA, the ENRE, and ENARSA. Furthermore, the Dam Safety Regulatory Body and water management and environmental protection authorities are invited to appoint a representative in the team. Additionally, ENARSA is entrusted with the technical audit of the power generation equipment.

The concessions' status report had to be submitted within two years for the HIDISA and HINISA concessions, expiring in 2024, whereas the term for issuing the report for HPPL, which concession expires in 2029, would be later determined. Subsequently, SE Resolution No. 486/23 modified the deadlines for the submission of reports by the ETAHC. In the case of HINISA and HIDISA, the ETAHC's deadline for the submission of the reports will be December 1, 2023 and April 19, 2024, respectively.

Later, SE Resolution No. 574/23, making use of the provisions of the concession agreements, provided that the current Alicurá, El Chocón Arroyito, Cerros Colorados and Piedra del Águila's concessionaires should continue in charge of their operation and maintenance for a 60-day term following termination of the concession. ENARSA was appointed as an observer, with broad powers during the transition term. To assist ENARSA during that period, the provinces of Neuquén and Río Negro were invited to appoint a representative to act jointly with the representative to be appointed by the National Ministry of Economy.

In October 2023, SE Resolution No. 815/23 granted an additional extension of the Alicurá, El Chocón, Arroyito and Cerros Colorados Hydroelectric Power Plants' concessions for 100 calendar days as from the expiration of the 60-day term provided by SE Resolution No. 574/23. On January 17, 2024, through SE Resolution No. 2/24, a new 60-calendar day extension was granted following the termination of the previous extensions, maintaining ENARSA in its role of observer.

NOTE 21: DOCUMENTATION KEEPING

On August 14, 2014, the CNV issued General Resolution No. 629, which introduced modifications to the provisions applicable to the keeping and conservation of corporate and accounting books and commercial documentation. To such effect, the Company, have sent non-sensitive work papers and information corresponding to the periods not covered by the statute of limitations for their keeping in the Administración de Archivos S.A. (AdeA)'s data warehouse located at Ruta 36, km 34.5, Florencio Varela, Province of Buenos Aires and in the Iron Mountain Argentina S.A.'s data warehouses located at the following addresses:

-	Azara 1245 - C.A.B.A.

-	Don Pedro de Mendoza 2163 - C.A.B.A.

-	Amancio Alcorta 2482 - C.A.B.A.

-	San Miguel de Tucumán 601, Carlos Spegazzini, Municipality of Ezeiza, Province of Buenos Aires.

A list of the documentation delivered for storage, as well as the documentation provided for in Article 5.a.3) Section I, Chapter V, Title II of the PROVISIONS (2013 regulatory provisions and amending rules), is available at the Company headquarters.

NOTE 22: OIL AND GAS RESERVES (Information not covered by the auditors' report)

The table below presents the estimated proved reserves of oil (including crude oil, condensate and LNG) and natural gas, by geographic area as of December 31, 2023.

	Proved Reserves
	Proved Developed		Proved Undeveloped		Total Proved
	Oil and LNG (1)	Natural Gas (2)		Oil and LNG (1)	Natural Gas (2)		Oil and LNG (1)	Natural Gas (2)
Argentina	7,592	20,523		3,994	11,312		11,586	31,835
Total at 12.31.2023	7,592	20,523		3,994	11,312		11,586	31,835

(1)	In thousands of barrels.

(2)	In millions of cubic meters.

NOTE 23: SUBSEQUENT EVENTS

Remuneration for sales to the spot market

Pursuant to SE Resolution No. 9/23 dated February 8, 2024, remuneration values for spot energy generation were updated, providing for a 73.9% increase on the values approved by SE Resolution No. 869/23 as from the February 2024 economic transaction.

165