PBR.A Petroleo Brasileiro ADR

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 6-K

 

Report of Foreign Private Issuer
Pursuant to Rule 13a-16 or 15d-16 of the

Securities Exchange Act of 1934

 

For the month of March, 2024

 

Commission File Number 1-15106

 

 

PETRÓLEO BRASILEIRO S.A. – PETROBRAS

(Exact name of registrant as specified in its charter)

 

Brazilian Petroleum Corporation – PETROBRAS

(Translation of Registrant's name into English)

 

Avenida Henrique Valadares, 28 – 19th floor 
20231-030 – Rio de Janeiro, RJ
Federative Republic of Brazil

(Address of principal executive office)

 

Indicate by check mark whether the registrant files or will file annual reports under cover Form 20-F or Form 40-F. 

Form 20-F ___X___ Form 40-F _______

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

Yes _______ No___X____

 

 

 

 

INDEX

Petróleo Brasileiro S.A. – Petrobras

 

 

Consolidated Statements of Financial Position	3
Consolidated Statements of Income	4
Consolidated Statements of Comprehensive Income	5
Consolidated Statements of Cash Flows	6
Consolidated Statements of Changes In Shareholders’ Equity	7

1	The Company and its operations	8
2	Basis of preparation	8
3	Material accounting policies	9
4	Judgments and sources of estimation uncertainty	9
5	Climate Change	16
6	New standards and interpretations	21
7	Capital Management	21
8	Cash and cash equivalents and marketable securities	22
9	Sales revenues	23
10	Costs and expenses by nature	26
11	Other income and expenses, net	27
12	Net finance income (expense)	28
13	Information by operating segment	28
14	Trade and other receivables	34
15	Inventories	36
16	Trade payables	37
17	Taxes	37
18	Employee benefits	42
19	Provisions for legal proceedings, judicial deposits and contingent liabilities	56
20	Provision for decommissioning costs	66
21	Other assets and liabilities	68
22	The “Lava Jato (Car Wash) Operation” and its effects on the Company	69
23	Commitment to purchase natural gas	69
24	Property, plant and equipment	70
25	Intangible assets	74
26	Impairment	76
27	Exploration and evaluation of oil and gas reserves	82
28	Collateral for crude oil exploration concession agreements	85
29	Consortia (partnerships) in E&P activities	85
30	Investments	88
31	Disposal of assets and other transactions	91
32	Finance debt	94
33	Lease liability	98
34	Equity	101
35	Risk management	106
36	Related-party transactions	114
37	Supplemental information on statement of cash flows	118
38	Subsequent events	118

Supplementary information on Oil and Gas Exploration and Production (unaudited)	120
Independent auditor's report on the consolidated financial statements	132

 

Consolidated Statements of Financial Position

PETROBRAS

As of December 31, 2023 and December 31, 2022 (Expressed in millions of US Dollars, unless otherwise indicated)

 

Assets	Note	12.31.2023	12.31.2022
Cash and cash equivalents	8	12,727	7,996
Marketable securities	8	2,819	2,773
Trade and other receivables	14	6,135	5,010
Inventories	15	7,681	8,779
Recoverable income taxes	17	218	165
Other recoverable taxes	17	960	1,142
Others	21	1,570	1,777
		32,110	27,642
Assets classified as held for sale	31	335	3,608
Current assets		32,445	31,250
Trade and other receivables	14	1,847	2,440
Marketable securities	8	2,409	1,564
Judicial deposits	19	14,746	11,053
Deferred income taxes	17	965	832
Other recoverable taxes	17	4,516	3,778
Others	21	2,315	1,553
Long-term receivables		26,798	21,220
Investments	30	1,358	1,566
Property, plant and equipment - PP&E	24	153,424	130,169
Intangible assets	25	3,042	2,986
Non-current assets		184,622	155,941
Total assets		217,067	187,191

 

Liabilities	Note	12.31.2023	12.31.2022
Trade payables	16	4,813	5,464
Finance debt	32	4,322	3,576
Lease liability	33	7,200	5,557
Income taxes payable	17	1,300	2,883
Other taxes payable	17	4,166	3,048
Dividends payable	34	3,539	4,171
Provision for decommissioning costs	20	2,032	−
Employee benefits	18	2,932	2,215
Others	21	3,015	3,001
		33,319	29,915
Liabilities related to assets classified as held for sale	31	541	1,465
Current liabilities		33,860	31,380
Finance debt	32	24,479	26,378
Lease liability	33	26,599	18,288
Income taxes payable	17	299	302
Deferred income taxes	17	10,910	6,750
Employee benefits	18	15,579	10,675
Provisions for legal proceedings	19	3,305	3,010
Provision for decommissioning costs	20	21,171	18,600
Others	21	1,890	1,972
Non-current liabilities		104,232	85,975
Current and non-current liabilities		138,092	117,355
Share capital (net of share issuance costs)	34	107,101	107,101
Capital reserve and capital transactions		410	1,144
Profit reserves	34	72,641	66,434
Accumulated other comprehensive deficit		(101,569)	(105,187)
Attributable to the shareholders of Petrobras		78,583	69,492
Non-controlling interests	30	392	344
Equity		78,975	69,836
Total liabilities and equity		217,067	187,191
The notes form an integral part of these financial statements.

Consolidated Statements of Income

PETROBRAS

Years ended December 31, 2023, 2022 and 2021 (Expressed in millions of US Dollars, unless otherwise indicated)

 

 

	Note	2023	2022	2021
Sales revenues	9	102,409	124,474	83,966
Cost of sales	10	(48,435)	(59,486)	(43,164)
Gross profit		53,974	64,988	40,802
Income (expenses)
Selling expenses	10	(5,038)	(4,931)	(4,229)
General and administrative expenses	10	(1,594)	(1,332)	(1,176)
Exploration costs	27	(982)	(887)	(687)
Research and development expenses		(726)	(792)	(563)
Other taxes		(890)	(439)	(406)
Impairment (losses) reversals, net	26	(2,680)	(1,315)	3,190
Other income and expenses, net	11	(4,031)	1,822	653
		(15,941)	(7,874)	(3,218)
Income before net finance expense, results of equity-accounted investments and income taxes		38,033	57,114	37,584
Finance income		2,169	1,832	821
Finance expenses		(3,922)	(3,500)	(5,150)
Foreign exchange gains (losses) and inflation indexation charges		(580)	(2,172)	(6,637)
Net finance expense	12	(2,333)	(3,840)	(10,966)
Results of equity-accounted investments	30	(304)	251	1,607
Net income before income taxes		35,396	53,525	28,225
Income taxes	17	(10,401)	(16,770)	(8,239)
Net income for the year		24,995	36,755	19,986
Net income attributable to shareholders of Petrobras		24,884	36,623	19,875
Net income attributable to non-controlling interests		111	132	111
Basic and diluted earnings per common and preferred share - in U.S. dollars	34	1.91	2.81	1.52
The notes form an integral part of these financial statements.

Consolidated Statements of Comprehensive Income

PETROBRAS

Years ended December 31, 2023, 2022 and 2021 (Expressed in millions of US Dollars, unless otherwise indicated)

 

	Note	2023	2022	2021
Net income for the year		24,995	36,755	19,986
Items that will not be reclassified to the statement of income:
Actuarial gains (losses) on post-employment defined benefit plans	18
Recognized in equity		(3,574)	(1,583)	5,169
Deferred income tax		271	212	(1,340)
		(3,303)	(1,371)	3,829
Items that may be reclassified subsequently to the statement of income:
Unrealized gains (losses) on cash flow hedge - highly probable future exports	35
Recognized in equity		4,554	5,223	(3,949)
Reclassified to the statement of income		3,763	4,871	4,585
Deferred income tax		(2,830)	(3,432)	(215)
		5,487	6,662	421
Translation adjustments (1)
Recognized in equity		1,186	975	(1,314)
Reclassified to the statement of income		−	−	41
		1,186	975	(1,273)
Share of other comprehensive income (loss) in equity-accounted investments	30
Recognized in equity		267	219	22
Other comprehensive income (loss)		3,637	6,485	2,999
Total comprehensive income		28,632	43,240	22,985
Comprehensive income attributable to shareholders of Petrobras		28,502	43,084	22,961
Comprehensive income attributable to non-controlling interests		130	156	24
(1) It includes cumulative translation adjustments in associates and joint ventures.
The notes form an integral part of these financial statements.

 

 

Consolidated Statements of Cash Flows

PETROBRAS

Years ended December 31, 2023, 2022 and 2021 (Expressed in millions of US Dollars, unless otherwise indicated)

	Note	2023	2022	2021
Cash flows from operating activities
Net income for the year		24,995	36,755	19,986
Adjustments for:
Pension and medical benefits	18	1,542	1,228	2,098
Results of equity-accounted investments	30	304	(251)	(1,607)
Depreciation, depletion and amortization	37	13,280	13,218	11,695
Impairment of assets (reversals), net	26	2,680	1,315	(3,190)
Inventory write down (write-back) to net realizable value	15	(7)	11	(1)
Allowance (reversals) for credit loss on trade and other receivables, net		40	65	(30)
Exploratory expenditure write-offs	27	421	691	248
Gain on disposal/write-offs of assets	11	(1,295)	(1,144)	(1,900)
Foreign exchange, indexation and finance charges		2,498	4,557	10,795
Income taxes	17	10,401	16,770	8,239
Revision and unwinding of discount on the provision for decommissioning costs		2,052	745	661
PIS and COFINS recovery - exclusion of ICMS (VAT tax) from the basis of calculation		−	(1)	(986)
Results from co-participation agreements in bid areas	11	(284)	(4,286)	(631)
Assumption of interest in concessions		−	−	(164)
Early termination and cash outflows revision of lease agreements		(415)	(629)	(545)
Losses with legal, administrative and arbitration proceedings, net	11	797	1,362	740
Decrease (Increase) in assets
Trade and other receivables		88	355	(2,075)
Inventories		1,564	(1,217)	(2,334)
Judicial deposits		(1,723)	(1,709)	(1,141)
Other assets		324	(413)	(289)
Increase (Decrease) in liabilities
Trade payables		(954)	(359)	1,073
Other taxes payable		(431)	(2,441)	2,835
Pension and medical benefits		(927)	(2,130)	(2,239)
Provisions for legal proceedings		(591)	(380)	(643)
Other employee benefits		356	(182)	(312)
Provision for decommissioning costs		(902)	(602)	(730)
Other liabilities		(569)	(95)	376
Income taxes paid		(10,032)	(11,516)	(2,138)
Net cash provided by operating activities		43,212	49,717	37,791
Cash flows from investing activities
Acquisition of PP&E and intangible assets		(12,114)	(9,581)	(6,325)
Acquisition of equity interests		(24)	(27)	(24)
Proceeds from disposal of assets - Divestment		3,606	4,846	4,783
Financial compensation from co-participation agreements		391	7,284	2,938
Divestment (Investment) in marketable securities		98	(3,328)	4
Dividends received		88	374	781
Net cash (used in) provided by investing activities		(7,955)	(432)	2,157
Cash flows from financing activities
Changes in non-controlling interest		1	63	(24)
Proceeds from finance debt	32	2,210	2,880	1,885
Repayment of principal - finance debt	32	(4,193)	(9,334)	(21,413)
Repayment of interest - finance debt	32	(1,978)	(1,850)	(2,229)
Repayment of lease liability	33	(6,286)	(5,430)	(5,827)
Dividends paid to Shareholders of Petrobras	34	(19,670)	(37,701)	(13,078)
Share repurchase program	34	(735)	−	−
Dividends paid to non-controlling interests		(49)	(81)	(105)
Net cash used in financing activities		(30,700)	(51,453)	(40,791)
Effect of exchange rate changes on cash and cash equivalents		174	(316)	(402)
Net change in cash and cash equivalents		4,731	(2,484)	(1,245)
Cash and cash equivalents at the beginning of the year		7,996	10,480	11,725
Cash and cash equivalents at the end of the year		12,727	7,996	10,480
The notes form an integral part of these financial statements.

 

Consolidated Statements of Changes In Shareholders’ Equity

PETROBRAS

Years ended December 31, 2023, 2022 and 2021 (Expressed in millions of US Dollars, unless otherwise indicated)

Share capital (net of share issuance costs)

Accumulated other comprehensive income (deficit) and deemed cost

Profit Reserves

Share Capital

Share issuance costs

Capital reserve, Capital Transactions and Treasury shares

Cumulative translation adjustments

Cash flow hedge - highly probable future exports

Actuarial gains (losses) on defined benefit pension plans

Other comprehensive income (loss) and deemed cost

Legal

Statutory

Tax incentives

Profit retention

Additional dividends proposed

Retained earnings (losses)

Equity attributable to shareholders of Petrobras

Non-controlling interests

Total consolidated equity

Balance at January 1, 2021

107,380

(279)

1,064

(73,936)

(24,590)

(15,034)

(1,174)

8,813

2,900

1,102

51,974

1,128

−

59,348

528

59,876

107,101

1,064

(114,734)

65,917

−

59,348

528

59,876

Capital increase with reserves

−

−

−

−

−

−

−

−

−

−

−

−

−

−

2

2

Capital transactions

−

−

79

−

−

−

−

−

−

−

−

−

−

79

(40)

39

Net income

−

−

−

−

−

−

−

−

−

−

−

−

19,875

19,875

111

19,986

Other comprehensive income (loss)

−

−

−

(1,186)

421

3,829

22

−

−

−

−

−

−

3,086

(87)

2,999

Appropriations:

Additional dividends proposed last year approved this year

−

−

−

−

−

−

−

−

−

−

−

(1,128)

−

(1,128)

−

(1,128)

Transfer to reserves

−

−

−

−

−

−

−

956

184

118

388

−

(1,646)

−

−

−

Dividends

−

−

−

−

−

−

−

−

−

−

(312)

6,688

(18,229)

(11,853)

(109)

(11,962)

Balance at December 31, 2021

107,380

(279)

1,143

(75,122)

(24,169)

(11,205)

(1,152)

9,769

3,084

1,220

52,050

6,688

−

69,407

405

69,812

107,101

1,143

(111,648)

72,811

−

69,407

405

69,812

Capital transactions

−

−

1

−

−

−

−

−

−

−

−

−

−

1

(146)

(145)

Net income

−

−

−

−

−

−

−

−

−

−

−

−

36,623

36,623

132

36,755

Other comprehensive income (loss)

−

−

−

951

6,662

(1,371)

219

−

−

−

−

−

−

6,461

24

6,485

Expired unclaimed dividends

−

−

−

−

−

−

−

−

−

−

−

−

11

11

−

11

Appropriations:

Additional dividends proposed last year approved this year

−

−

−

−

−

−

−

−

−

−

−

(6,688)

−

(6,688)

−

(6,688)

Transfer to reserves

−

−

−

−

−

−

−

1,805

197

457

71

−

(2,530)

−

−

−

Dividends

−

−

−

−

−

−

−

−

−

−

(9,083)

6,864

(34,104)

(36,323)

(71)

(36,394)

Balance at December 31, 2022

107,380

(279)

1,144

(74,171)

(17,507)

(12,576)

(933)

11,574

3,281

1,677

43,038

6,864

−

69,492

344

69,836

107,101

1,144

(105,187)

66,434

−

69,492

344

69,836

Treasury shares

−

−

(735)

−

−

−

−

−

−

−

−

−

−

(735)

−

(735)

Capital transactions

−

−

1

−

−

−

−

−

−

−

−

−

−

1

1

2

Net income

−

−

−

−

−

−

−

−

−

−

−

−

24,884

24,884

111

24,995

Other comprehensive income (loss)

−

−

−

1,167

5,487

(3,303)

267

−

−

−

−

−

−

3,618

19

3,637

Expired unclaimed dividends

−

−

−

−

−

−

−

−

−

−

−

−

7

7

−

7

Appropriations:

Additional dividends proposed last year approved this year

−

−

−

−

−

−

−

−

−

−

−

(6,864)

−

(6,864)

−

(6,864)

Transfer to reserves

−

−

−

−

−

−

−

1,272

8,544

321

−

−

(10,137)

−

−

−

Dividends

−

−

−

−

−

−

−

−

−

−

−

2,934

(14,754)

(11,820)

(83)

(11,903)

Balance at December 31, 2023

107,380

(279)

410

(73,004)

(12,020)

(15,879)

(666)

12,846

11,825

1,998

43,038

2,934

−

78,583

392

78,975

107,101

410

(101,569)

72,641

−

78,583

392

78,975

The notes form an integral part of these financial statements.

 

1.	The Company and its operations

Petróleo Brasileiro S.A. (Petrobras), hereinafter referred to as “Petrobras” or “Company,” is a partially state-owned enterprise, controlled by the Brazilian Federal Government, of indefinite duration, governed by the terms and conditions under the Brazilian Corporate Law (Law 6,404 of December 15, 1976), Law 13,303 of June 30, 2016 and its Bylaws.

Petrobras’ shares are listed on the Brazilian stock exchange (B3) in the Level 2 of Corporate Governance special listing segment and, therefore, the Company, its shareholders, its managers and fiscal council members are subject to provisions under its regulation (Level 2 Regulation - Regulamento de Listagem do Nível 2 de Governança Corporativa da Brasil Bolsa Balcão – B3). The provisions of the Level 2 Regulation shall prevail over statutory provisions in the event of harm to the rights of public offers investors provided for in the Company's Bylaws, except when otherwise determined by other regulation.

The Company is dedicated to prospecting, drilling, refining, processing, trading and transporting crude oil from producing onshore and offshore oil fields and from shale or other rocks, as well as oil products, natural gas and other liquid hydrocarbons. In addition, Petrobras carries out energy related activities, such as research, development, production, transport, distribution and trading of all forms of energy, as well as other related or similar activities.

Petrobras may perform any of the activities related to its corporate purpose, directly, through its wholly-owned subsidiaries, controlled companies, alone or through joint ventures with third parties, in Brazil or abroad.

The economic activities linked to its business purpose shall be undertaken by the Company in free competition with other companies according to market conditions, in compliance with the other principles and guidelines of Laws no. 9,478/97 and 14,134/21 (oil and gas regulations, respectively). However, Petrobras may have its activities, provided they are in compliance with its corporate purpose, guided by the Brazilian Federal Government to contribute to the public interest that justified its creation, aiming to meet national energy policy objectives when:

I – established by law or regulation, as well as under agreements provisions with a public entity that is competent to establish such obligation, abiding with the broad publicly stated of such instruments; and

II – the cost and revenues thereof have been broken down and disseminated in a transparent manner.

In this case, the Company’s Investment Committee and Minority Shareholders Committee, exercising their advisory role to the Board of Directors, shall assess and measure the difference between such market conditions and the operating result or economic return of the transaction, based on technical and economic criteria for investment valuation and specific operating costs and results under the Company's operations. In case a difference is identified, for every financial year, the Brazilian Federal Government shall compensate the Company.

2.	Basis of preparation

2.1.	Statement of compliance and authorization of consolidated financial statements

These consolidated financial statements have been prepared and are being presented in accordance with the International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB).

The consolidated financial statements have been prepared under the historical cost convention, except when otherwise indicated. The significant accounting policies used in the preparation of these financial statements are set out in their respective explanatory notes.

The preparation of the financial statements requires the use of estimates based on assumptions and judgements, which may affect the application of accounting policies and reported amounts of assets, liabilities, revenues and expenses. Actual results may differ from these estimates. Relevant estimates and judgments with a higher level of complexity are disclosed in explanatory note 4.

These consolidated financial statements were approved and authorized for issue by the Company’s Board of Directors in a meeting held on March 7, 2024.

2.2.	Functional and presentation currency

The functional currency of Petrobras and all of its Brazilian subsidiaries is the Brazilian Real. The functional currency of the Petrobras direct subsidiaries that operate outside Brazil is the U.S. dollar.

Petrobras has selected the U.S. dollar as its presentation currency to facilitate a more direct comparison to other oil and gas companies. The financial statements have been translated from the functional currency (Brazilian real) into the presentation currency (U.S. dollar). All assets and liabilities are translated into U.S. dollars at the closing exchange rate at the date of the financial statements; income and expenses, as well as cash flows are translated into U.S. dollars using the average exchange rates prevailing during the period. All exchange differences arising from the translation of the consolidated financial statements from the functional currency into the presentation currency are recognized as cumulative translation adjustments (CTA) within accumulated other comprehensive income in the consolidated statements of changes in shareholders’ equity.

Brazilian Real x U.S. Dollar	Dec/23	Sep/23	Jun/23	Mar/23	Dec/22	Sep/22	Jun/22	Mar/22	Dec/21	Sep/21	Jun/21	Mar/21
Quarterly average exchange rate	4.96	4.88	4.95	5.20	5.26	5.25	4.93	5.23	5.59	5.23	5.29	5.48
Period-end exchange rate	4.84	5.01	4.82	5.08	5.22	5.41	5.24	4.74	5.58	5.44	5.00	5.70

 

 

3.	Material accounting policies

To aid cohesion and comprehension, the significant accounting policies are set out at the end of each explanatory note to which they relate.

4.	Judgments and sources of estimation uncertainty

The preparation of the consolidated financial information requires the use of estimates and judgments for certain transactions. Next is presented key judgments and the main sources of estimation uncertainty with a significant risk of causing material adjustments to the Company's key accounting estimates over the next fiscal year.

4.1.	Recognition of exploration costs and oil and natural gas reserves estimates

After obtaining the legal rights to explore a specific area, the Company uses the successful efforts method to recognize costs incurred in connection with the exploration and evaluation of mineral resources, before demonstrating technical and commercial feasibility of extracting those resources. This method requires a direct relationship between costs incurred and mineral resources for these costs to be characterized as assets. The types of exploration costs and their respective recognition are presented in note 27.

The moment in which the technical and commercial feasibility of extracting a mineral resource is determined requires management judgments. An internal commission of technical executives of the Company periodically reviews the conditions of each well, by analysis of geological, geophysical and engineering data, as well as economic conditions, operating methods and government regulations.

The Company considers that the technical and commercial feasibility of a mineral resource can be demonstrated when the project has all the necessary information to characterize the reservoir as a proved reserve. Costs associated with non-commercial mineral resources are recognized as expenses in the period when identified.

According to the definitions prescribed by the SEC, proved oil and natural gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically feasible from a given date, from known reservoirs and under existing economic conditions, operating methods and government regulation.

The Company also determines reserves according to the criteria of the ANP/SPE (National Agency for Petroleum, Natural Gas and Biofuels / Society of Petroleum Engineers). The main differences between these criteria and the SEC criterion are related to the use of different economic assumptions and the possibility of considering as reserves, in the ANP/SPE criteria, the volumes expected to be produced beyond the concession contract expiration date in fields in Brazil, according to the ANP technical reserves regulations.

4.2.	Impairment testing

4.2.1.

Sources of estimation uncertainty related to impairment testing

Impairment testing involves uncertainties mainly related to: (a) the average Brent prices and to the Brazilian real/U.S. dollar average exchange rate, whose estimates are relevant to virtually all of the Company's operating segments; (b) discount rates; and (c) estimated proved and probable reserves (according to the criteria established by the ANP/SPE, as described in note 4.1). A significant number of interdependent variables are derived from these key assumptions and there is a high degree of complexity in their application in determining value in use for impairment testing.

A sensitivity analysis for assets or CGUs most sensitive to future impairment losses or reversals in the next year is presented in note 26.

Average Brent prices and average exchange rate

The markets for crude oil and natural gas have a history of significant price volatility and, although prices can drop or increase precipitously, industry prices over the long term tends to continue being driven by market supply and demand fundamentals.

Brent prices and exchange rate projections are derived from the Strategic Plan and are consistent with market evidence, such as independent macro-economic forecasts, industry analysts and experts. Backtesting analysis and feedback processes in order to continually improve forecast techniques are also performed.

The Company’s oil price forecast model is based on a nonlinear relationship between variables reflecting market supply and demand fundamentals. This model also takes into account other relevant factors, such as the effects of the Organization of the Petroleum Exporting Countries (OPEC) decisions on the oil market, industry costs, idle capacity, oil and gas production forecasted by specialized firms, and the relationship between the oil price and the Brazilian Real/U.S. dollar exchange rate.

The process of projecting Brazilian Real/U.S. dollar exchange rate is based on econometric models that consider long-term assumptions involving observable inputs, such as commodity prices, country risk, interest rates in the U.S. and the value of the U.S. dollar relative to a basket of foreign currencies (U.S. Dollar Index – USDX).

Changes in the economic environment may result in changing assumptions and, consequently, the recognition of impairment losses or reversals on certain assets or CGUs. For example, the Company’s sales revenues and refining margins are directly impacted by Brent price variations, as well as Brazilian Real/U.S. dollar exchange rate variations, which also impacts our capital and operating expenditures.

Note 26 presents Brent prices and exchange rate estimates.

Discount rates

The discount rates used in impairment tests reflect specific risks associated with the estimated cash flows of the assets or CGUs. For example, changes in the economic and political environment may result in higher country risk projections, causing increases in the discount rates used in impairment tests, as well as investment decisions that result in the postponement or interruption of projects considering specific risks related to non-completion or delayed start of operations.

Note 26 presents the main discount rates applied in impairment tests.

Estimated proved and probable reserves

Reserves estimates, according to the criteria established by the ANP/SPE (as set out in note 4.1) are revised at least annually, based on updated geological and production data of reservoirs, as well as on changes in prices and costs used in these estimates. Revisions may also result from significant changes in the Company’s strategy for development projects or in the production capacity.

Although the Company is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a sort of factors including completion of development projects, reservoir performance, regulatory aspects and significant changes in long-term oil and gas price levels.

4.2.2.

Identifying cash-generating units for impairment testing

A cash-generating unit (CGU) represents the smaller identifiable group of assets that generate cash inflows, which are largely independent of the cash inflows of other assets or groups of assets. Identifying CGUs requires management assumptions and judgment, based on the Company’s business and management model. The level of asset disaggregation in CGUs can reach the limit of assets being tested individually.

Changes in CGUs resulting from the review of investment, strategic or operational factors, may result in changes in the interdependencies of assets and, consequently, alter the aggregation or breakdown of assets that were part of certain CGUs, which may influence their ability to generate cash and cause additional losses or reversals in the recovery of such assets. If the approval for the sale of a CGU’s component occurs between the reporting date and the date of the issuance of the consolidated financial statements, the Company reassesses whether the value in use of this component, estimated with the information existing at the reporting date, reasonably represents its fair value, net of disposal expenses. Such information must include evidence of the stage at which management was committed to the sale of the CGU’s component.

The primary considerations in identifying the CGUs are set out as follows:

a)

Exploration and Production CGUs:

i)

Crude oil and natural gas producing properties - individual CGUs: comprise assets related to exploration and production development of a field or a cluster (group of two or more fields) in Brazil and abroad. At December 31, 2023, there are 33 fields and 15 clusters representing different Exploration and Production CGUs in Brazil.

ii)

Equipment not related to crude oil and natural gas producing properties: comprise platforms, drilling rigs and other assets which are not part of any CGU and are assessed for impairment separately.

b)

Refining, transportation and marketing CGUs:

i) Downstream CGU: comprises refineries and associated assets, terminals and pipelines, as well as logistics assets operated by Transpetro, with a combined and centralized operation of such assets in Brazil. These assets are managed with a common goal of serving the market at the lowest overall cost, preserving the strategic value of the whole set of assets in the long term. The operational planning is made in a centralized manner and these assets are not managed, measured or evaluated by their individual results. Refineries do not have autonomy to choose the oil to be processed, the mix of oil products to produce, the markets in which these products will be traded, which amounts will be exported, which intermediaries will be received and to decide the sale prices of oil products. Operational decisions are analyzed through an integrated model of operational planning for market supply, considering all the options for production, imports, exports, logistics and inventories, seeking to maximize the Company’s global performance. The decision on new investments is not based on the profitability of the project where the asset will be installed, but on the additional result for the CGU as a whole. The model that supports the entire planning, used in technical and economic feasibility studies of new investments in refining and logistics, seeks to allocate a certain type of oil, or a mix of oil products, define market supply (area of influence), aiming at achieving the best integrated results. Pipelines and terminals are a complementary and interdependent portion of the refining assets, required to supply the market.

ii) CGU Itaboraí Utilities: composed of assets that will support the natural gas processing plant (UPGN) of the route 3 integrated project;

iii) CGU GasLub: set of assets that remain in hibernation and are being evaluated for use in other projects.

iv) CGU Second Refining Unit of RNEST: comprises assets of the second refining unit of Abreu e Lima refinery;

v) Transportation CGU: comprises assets relating to Transpetro’s fleet of vessels;

vi) Hidrovia CGU: comprises the fleet of vessels under construction of the Hidrovia project (transportation of ethanol along the Tietê River);

vii) CGU nitrogen fertilizer plants: formed by hibernated nitrogen fertilizer plants; and

viii) Other operations abroad defined as the smallest group of assets that generates independent cash flows.

c)

Gas and Low Carbon Energies CGUs:

i) CGU Integrated Processing System: set of assets formed by natural gas processing plants in Itaboraí, Cabiúnas and Caraguatatuba, grouped together due to the contractual characteristics of the Integrated Processing System and the Integrated Transportation System;

ii) CGUs of Natural Gas Processing Plants: each remaining natural gas processing plant represents a separate CGU.

iii) CGU Power: comprises the thermoelectric power generation plants (UTEs). The operation and trade of energy of this CGU are carried out and coordinated in an integrated manner. The economic results of each of the plants in the integrated portfolio are highly dependent on each other, due to operational optimization aimed at maximizing the overall result.

iv) Other CGUs: operations abroad defined as the smallest group of assets that generates largely independent cash flows.

v) Biodiesel CGU: an integrated unit of biodiesel plants defined based on the production planning and operation process, that takes into consideration domestic market conditions, the production capacity of each plant, as well as the results of biofuels auctions and raw materials supply.

vi) Quixadá CGU: comprises the assets of Quixadá Biofuel Plant.

Further information on impairment testing is set out in note 26.

4.3.

Sources of estimation uncertainty related to depreciation, depletion and amortization

As presented in note 24, assets directly related to the oil and gas production are depleted using the units of production method, based on monthly production in relation to the respective developed proved reserves, except for the signature bonuses, where total proved reserves are used.

Proved developed reserves are those for which recovery can be expected: (i) through existing wells, equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through extraction equipment and operational infrastructure installed at the time of the reserves estimate, if the extraction is carried out by means that do not involve a well.

Estimates of proved reserves volumes used in the unit-of-production method are prepared by Company’s technicians according to the SEC definitions (as described in note 4.1). Revisions to the Company’s proved developed and undeveloped reserves impact prospectively the amounts of depreciation, depletion and amortization recognized in the statement of income and the carrying amounts of oil and gas properties assets. Information on uncertainties related to reserve volume estimates are presented in note 4.1.

Therefore, considering all other variables being constant, a decrease in estimated proved reserves would increase, prospectively, depreciation, depletion and amortization expense, while an increase in reserves would reduce depreciation, depletion and amortization.

4.4.

Sources of estimation uncertainty related to pension plan and other post-employment benefits

The net actuarial liability represents the Company's actuarial obligations, net of fair value of plan assets (when applicable), at present value, as described in note 18.3.2.

The actuarial obligations and net expenses related to defined benefit pension and health care post-employment plans are computed based on several financial and demographic assumptions, of which the most significant are:

a) Discount rate: comprises the projected future inflation in addition to an equivalent discounted interest rate that matches the duration of the pension and health care obligations with the future yield curve of long-term Brazilian Government Bonds; and

b) Medical costs: comprise the projected growth rates based on per capita health care benefits paid over the last five years, which are used as a basis for projections, converged to the general price inflation index within 30 years.

These and other assumptions are revised at least annually and may differ materially from actual results due to changing market and financial conditions, as well as actual results of actuarial assumptions.

The measurement uncertainties associated with the defined benefit obligation and a sensitivity analysis of discount rates and changes in medical costs are disclosed in notes 18.3.6 and 18.3.7, respectively.

4.5.

Sources of estimation uncertainty related to provisions for legal proceedings and contingencies

The Company is part in arbitrations and in legal and administrative proceedings involving civil, tax, labor and environmental issues arising from the normal course of its business and makes use of estimates to recognize the amounts and the probability of outflow of resources, based on reports and technical assessments from legal advisors and on management’s assessment.

These estimates are performed individually, or aggregated if there are cases with similar characteristics, primarily considering factors such as assessment of the plaintiff’s demands, consistency of the existing evidence, jurisprudence on similar cases and doctrine on the subject. Specifically for lawsuits by outsourced employees, the Company estimates the expected loss based on a statistical procedure, due to the number of actions with similar characteristics.

Arbitral, legal and administrative decisions against the Company, new jurisprudence and changes of existing evidence can result in changes on the probability of outflow of resources and on the estimated amounts, according to the assessment of the legal basis.

Note 19 provides further detailed information about contingencies and legal proceedings.

4.6.

Sources of estimation uncertainty related to decommissioning costs

The Company has legal obligations to remove equipment and restore onshore and offshore areas at the end of operations. Its most significant asset removal obligations relate to offshore areas. Estimates of costs for future environmental cleanup and remediation activities are based on current information about costs and expected plans for remediation. The timing of abandonment and dismantling of areas is based on the length of reserves depletion, in accordance with the ANP/SPE definitions (as described in note 4.1). Therefore, revisions to reserves estimates that result in changes in the timing of reserves depletion may impact the provision for decommissioning cost. For additional information about revisions to the Company’s reserves estimates, see note 4.1.

These obligations are recognized at present value, using a risk-free discount rate, adjusted to the Company's credit risk. Changes in the discount rate can cause significant variations in the recognized amount, due to the long-term nature until abandonment. A sensitivity analysis of discount rates used in the calculation of the provision for decommissioning costs is presented in note 20.

The calculation to determine the amounts to be provisioned are complex, since: i) the obligations are long-term; ii) the contracts and regulations contain subjective definitions of the removal and remediation practices and criteria involved when the events occur; and iii) asset removal technologies and costs are constantly changing, along with regulations, environmental, safety and public relations considerations.

The Company constantly conducts studies to incorporate technologies and procedures to optimize the process of abandonment, considering industry best practices. However, the timing and amounts of future cash flows are subject to significant uncertainty.

Note 20 provides further information about provision for decommissioning costs.

4.7.

Sources of estimation uncertainty related to leases

The Company uses incremental borrowing rates to determine the present value of the lease payments, when the interest rate implicit in the lease cannot be readily determined.

The determination of incremental rates requires estimates based on corporate funding rates (obtained from the yields on bonds issued by Petrobras), which take into account the risk-free rate and the Company's credit risk premium, adjusted to also reflect the specific conditions and characteristics of the lease, such as the risk of the country's economic environment, guarantees, currency and duration of the payment flow.

The present value of lease liabilities is determined based on the incremental rates estimated at the start date of each lease. Therefore, even in cases where lease agreements have similar characteristics, their cash flows may be discounted at significantly different incremental rates depending on the Company's corporate funding rates on the start date of each lease.

Note 33 presents information on lease arrangements by class of underlying assets.

4.8.

Sources of estimation uncertainty related to cash flow hedge accounting involving the Company’s future exports

The Company determines its future exports as “highly probable future exports” based on its current Strategic Plan and on short-term estimates on a monthly basis. The highly probable future exports are determined by a percentage of projected exports revenues.

The estimate of the amount of highly probable future exports considers future uncertainty regarding the Brent oil prices, oil production and demand for products in a model which optimizes the Company's operations and investments, in addition to considering the historical profile of exported volume in relation to total oil production.

As described in note 35.2.2, foreign exchange gains and losses relating to the effective portion of hedging instrument are recognized in other comprehensive income and reclassified to the statement of income within finance income (expense) in the periods when the hedged item affects the statement of income. However, if future exports for which foreign exchange gains and losses hedging relationship has been designated is no longer expected to occur, any related cumulative foreign exchange gains or losses that have been recognized in other comprehensive income from the date the hedging relationship was designated to the date the Company revoked the designation is immediately recycled from other comprehensive income to the statement of income.

For the long-term, future exports forecasts are reviewed whenever the Company reviews its Strategic Plan assumptions, while for the short-term future exports are reviewed monthly. The approach for determining exports as highly probable future exports is reviewed annually, at least.

See note 35.2.2 for more detailed information about cash flow hedge accounting and a sensitivity analysis of the cash flow hedge involving future exports.

4.9.

Sources of estimation uncertainty related to income taxes

Income taxes rules and regulations may be interpreted differently by tax authorities, and situations may arise in which the tax authorities' interpretations differ from the Company's understanding.

Uncertainties over income taxes treatments represent the risks that the tax authority does not accept a certain tax treatment applied by the Company, mainly related to different interpretations of deductions and additions to the income taxes (Imposto de Renda sobre Pessoa Jurídica - IRPJ and Contribuição Social sobre Lucro Líquido - CSLL calculation basis. The Company evaluates each uncertain tax treatment separately or in a group where there is interdependence in relation to the expected result.

The Company estimates the probability of acceptance of an uncertain tax treatment by the tax authority based on technical assessments by its legal advisors, considering precedent jurisprudence applicable to current tax legislation, which may be impacted mainly by changes in tax rules or court decisions which may affect the analysis of the fundamentals of uncertainty. The tax risks identified are evaluated, treated and, when applicable, follows a pre-determined tax risk management methodology.

If it is probable that the tax authorities will accept an uncertain tax treatment, the amounts recorded in the financial statements are consistent with the tax records and, therefore, no uncertainty is reflected in the measurement of current or deferred income taxes. If it is not probable that the tax authorities will accept an uncertain tax treatment, the uncertainty is reflected in the measurement of current or deferred income taxes in the financial statements.

The effect of uncertainty for each uncertain tax treatment is estimated by using the method that provides the best prediction of the resolution of the uncertainty. The most probable amount method provides as an estimate the single most probable amount in a set of possible outcomes, while the expected amount method represents the sum of the amounts weighted by the probability in relation to a range of possible outcomes.

Additional information on uncertainty over income taxes treatments is disclosed in Note 17.1.

4.10.

Sources of estimation uncertainty related to expected credit losses

Credit losses correspond to the difference between all contractual cash flows owed to the Company and all cash flows that the entity expects to receive, discounted at the original effective interest rate. The expected credit loss of a financial asset corresponds to the average of expected credit losses weighted by the respective default risks.

Expected credit losses on financial assets are based on assumptions relating to risk of default, the determination of whether or not there has been a significant increase in credit risk, expectation of recovery, among others. The Company uses judgment for such assumptions in addition to information from credit rating agencies and inputs based on collection delays.

Notes 14.2 and 14.3 provide details on the expected credit losses recognized by the Company.

4.11.

Sources of estimation uncertainty related to the compensation for the surplus volume for the Transfer of Rights Agreement

As a result of the Second Bidding Round for the Surplus Volume of the Transfer of Rights Agreement under the Production Sharing regime, the Company signed amendments and new agreements in 2022 with partners in the Atapu and Sépia fields. Such agreements provide, in addition to the compensation already received upon signature, supplementary amounts that may be owed to the Company, according to the conditions described in note 25.2.

Additionally, over the last few years the Company has sold assets considered non-strategic and established partnerships in E&P assets aiming, among other objectives, at sharing risks and developing new technologies. Such transactions were carried out through partnerships (note 29) and divestments, with procedures aligned with current legislation and regulatory bodies. In some of these transactions, contingent receipts are also provided for, subject to contractual clauses (note 31.4).

5.	Climate Change

Climate change may result in both negative and positive effects for the Company. Potential negative effects of climate change for the Company are referred to as climate-related risks (climate risks). Conversely, potential positive effects arising from climate change for the Company are referred to as climate-related opportunities.

Climate risks are categorized as: (i) climate-related transition risks (transition risks); and (ii) climate-related physical risks (physical risks).

Transition risks arise from efforts to the transition to a low-carbon economy. In this category, the Company has identified the following risks that can reasonably be expected to affect its cash flows, access to financing or cost of capital:

Risk	Description	Time length (2)
Market	Worldwide: increasing demand for energy and products with lower carbon intensity leading to a reduction in oil demand, a consequent decline in prices of fossil fuel products. Preference for fossil fuel products with lower Greenhouse Gas (GHG) intensity in production processes. In Brazil: the demand for our products may be affected, especially by the increase in demand for alternative fuels, also stimulated by public policies such as the RENOVABIO(1) program, among others.	Medium to long-term
Technological	Loss of competitiveness due to the non-implementation or implementation of inefficient or non-effective technologies to reduce emissions from our operations and products.	Medium to long-term
Regulatory	Increased requirements for controls over GHG emissions in licensing processes, which may cause operational restrictions and financial penalties for our activities. Supplementing regulation for the adoption of a carbon pricing instrument in Brazil, considering its various aspects and possible formats.	Medium to long-term
Legal and Reputational	Litigation and/or reputational damage due to non-compliance with climate commitments.	Medium-term
(1) National Policy for Biofuels, aiming at increasing the production and use of biofuels in the Brazilian energy chain.
(2) Criteria adopted for the time horizon: short term (1 year), medium term (between 1 and 5 years), and long term (more than 5 years).

 

 

Physical risks result from climate change that can be event-driven (acute physical risk) or from long-term shifts in climate patterns (chronic physical risk). In this category, the Company has identified the following risks that can reasonably be expected to affect its cash flows, access to financing, or cost of capital:

Risk	Description	Time length(1)
Water shortage	Reduction in water availability affecting onshore facilities.	Medium to long-term
Meteoceanografic changes	Changes in patterns of wind, waves and currents may alter the operational conditions of our assets.	Long-term
(1) Criteria adopted for the time horizon: short term (1 year), medium term (between 1 and 5 years), and long term (more than 5 years).

 

 

 

5.1.

Potential effects of climate risks on accounting estimates

Accounting estimates are monetary amounts in financial statements that are subject to measurement uncertainty.

The following information used in relevant accounting estimates of the Company is largely determined based on the assumptions and projections of the Petrobras Strategic Plan (Strategic Plan):

•

value in use for impairment of assets testing purposes (note 4.2.1);

•

timing and costs used in measuring the provision for decommissioning costs (note 4.6);

•

highly probable future exports used in cash flow hedge accounting involving the Company’s future exports (note 4.8); and

•

useful life of PP&E and intangible assets used in measuring depreciation, depletion and amortization expenses (notes 24 and 25).

 

As presented in the following topic, the Company considered the effects related to climate risks in its Strategic Plan approved by the Board of Directors, which is updated annually, including actions to achieve its climate commitments and its long-term ambition to neutralize GHG emissions in activities under its control (scopes 1 and 2) by 2050.

The aforementioned ambition and commitments are not guarantees of future performance by the Company and are subject to assumptions that may prove incorrect and to risks and uncertainties that are difficult to predict.

a)

Transition risk to low carbon economy

The transition to a low-carbon economy brings market, technological, regulatory, legal and reputational risks, which were considered in the development of the Company's Strategic Plan. Such consideration was based on the following external environment assumptions that reflect the dynamics of the energy sector:

•

Moderate economic growth compared to the recent past;

•

Shifts in consumption habits and behaviors;

•

Public policies focusing on mobility, air quality and adaptation of urban infrastructure to climate change;

•

International coordination in efforts to reduce GHG emissions;

•

Reduction in the GHG emissions;

•

Reduction in the consumption of fossil fuels; and

•

Diffusion of end-use technologies that reduce the need for fossil fuel consumption.

 

As a result of this, demand and prices, both domestic and international, of the main products considered in the Strategic Plan are negatively affected.

In 2023, the Company adopted three distinct scenarios that are used for different purposes in its planning activities. These scenarios are called Adaptation, Negotiation, and Commitment. In all of them, there is a slowdown and subsequent contraction of fossil fuel sources. The Negotiation scenario, which is used as reference scenario for quantifying the Company's Strategic Plan, considers that fossil fuels, which currently represent approximately 80% of primary energy sources, will represent around 55% by 2050. The share of oil will decrease from the current 29% to around 21%.

The Brent price considered in the reference scenario of the Strategic Plan decreases from US$80 per barrel in 2024 to US$65 per barrel in 2050. For additional information about the behavior of the Brent price, considered in the Company's Strategic Plan reference scenario, please see note 26. The following table compares the oil price used in the reference scenario of the Strategic Plan for the years 2030 and 2050 with those projected in the Announced Pledges Scenario (APS) and Net Zero Emission (NZE) scenarios by the International Energy Agency (IEA):

Brent price US$/Barrel	2030	2050
Strategic Plan	65	65
APS	74	60
NZE	42	25

 

 

According to the IEA, the APS scenario considers that all climate commitments made by governments around the world, including Nationally Determined Contributions (NDCs), as well as long-term net-zero targets, will be met in full and on time, with an increase of approximately 1.7^oC in temperature by 2100 (with a 50% probability of occurrence). As for the NZE scenario, according to the IEA, it presents a pathway for the global energy sector to achieve net-zero CO₂ emissions by 2050, consistent with limiting the temperature increase to 1.5 °C (with at least a 50% probability of occurrence).

The Strategic Plan also includes Company's actions to achieve the carbon sustainability commitments, such as low-carbon Research and Development (R&D) projects and decarbonization projects for operations. These actions aim to address transition risks as well as reflect climate opportunities.

The Company's accounting estimates did not incorporate the effect of carbon price. Currently, there are uncertainties regarding the structure and dynamics of a future carbon market in Brazil, and there is no sufficient and reliable information available to assess the effects of carbon price.

a.1) Potential effects on the value in use in impairment tests

When measuring the value in use of its assets, the Company bases its cash flow projections on reasonable and supportable assumptions that represent management's best estimate of the range of economic conditions.

A faster transition to a low-carbon economy than projected in the Strategic Plan could result in Brent prices and demand for the Company’s products that are lower than the ones considered to estimate the value in use of the Company’s assets for impairment testing purposes.

Additionally, progress in the establishment of a regulated carbon market in Brazil may lead to the inclusion of the carbon price in calculations of the value in use of the Company’s assets for impairment testing purposes.

The reduction in the value in use of the Company's assets may result in the recognition of losses due to the non-recoverability of the carrying amounts of these assets.

Given that the oil price is a variable that decisively influences the recoverable amount of assets, the Company carried out a sensitivity analysis of the effect of using the Brent prices considered in the APS and NZE scenarios, for the impairment test of the Company's E&P assets in Brazil.

Using the prices in the APS and NZE scenarios to perform a sensitivity analysis on projected gross revenues deducted of production taxes, net of income taxes, and keeping unchanged all other components, variables, assumptions and data for calculating the recoverable amount, the Company's E&P segment, regarding the impairment loss recognized by the Company, as disclosed in note 26, would have additional impairment reversal of US$ 696 in the APS scenario and additional impairment losses US$ 6,611ind the NZE scenario, concentrated in the Campos basin fields.

The Company does not consider this sensitivity analysis, based on APS and NZE Brent price scenarios, to be the best estimates to determine expected effects on the recoverable amount of assets, sales revenues or net income.

Considering that the Company did not incorporate in its accounting estimates the carbon price effects, the Company carried out a sensitivity analysis of the effect of GHG emissions pricing costs on the impairment test of assets in the E&P segment in Brazil, considering a monetary charge per ton of CO₂ emission starting from 2028, and the existence of free emission allowances.

In this context, using a base price of US$ 10/CO₂ from 2024 to 2030, US$ 31/CO₂ in 2035, US$ 52/CO₂ in 2040, US$ 73/CO₂ in 2045, and US$ 95/CO₂ in 2050, including gradual emission exemptions, to simulate additional cash outflows (net of income taxes), and keeping all other components, variables, assumptions and data for the calculation of recoverable amount unchanged, the E&P segment would have an additional US$ 182 impairment loss.

The Company does not consider this sensitivity analysis of the effect of greenhouse gas emissions pricing costs on the impairment test of assets to be the best estimate to determine expected effects on the recoverable amount, neither the estimated effects on expenses nor net income.

a.2) Potential effects on decommissioning costs

Due to its operations, the Company has legal obligations to remove equipment and restore onshore and offshore areas. On December 31, 2023, the provision for decommissioning costs recognized by the Company totaled US$ 23,202, as set out in Note 20. On an undiscounted basis the nominal amount would be US$ 48,787.

The estimated timing used by the Company to account for decommissioning costs are consistent with the useful lives of the related assets. The average decommissioning period of oil and gas assets weighted by the carrying amounts of such assets is 14 years.

During 2023, there were no issuance of government regulations related to climate matters that changed or had potential to change the period for decommissioning the Company's assets, as well as not identifying any triggers that would accelerate the expected dates for decommissioning the Company's assets due to the Company’s climate goals and ambition to neutralize GHG emissions in activities under its control (scopes 1 and 2) by 2050.

A transition to a low-carbon economy that is faster than it was anticipated by the Company may accelerate the timing to remove equipment and restore onshore or offshore areas. Such acceleration would increase the present value of the decommissioning obligations recognized by the Company.

To illustrate the effect of a possible acceleration of the transition to a low-carbon economy, the Company estimates that the provision for decommissioning costs would increase by US$ 1,101, US$ 3,385 and US$ 5,478 if the timing currently used were brought forward by one, three and five years, respectively. This sensitivity analysis assumed that all other components, variables, assumptions and data for calculating the provision remained unchanged. The year ranges used are not intended to be predictions of likely future events or outcomes.

a.3) Potential effects on “highly probable future exports” used in cash flow hedge accounting involving the Company's future exports

A transition to a low-carbon economy that is faster than it was anticipated by the Company may negatively effect the Company's future exports. Such effect may result in certain exports, whose foreign exchange gains or losses were designated for hedge accounting, no longer be considered highly probable, but remain forecasted, or, depending on the magnitude of the transition and its speed, cease to be considered forecasted. Further details on the consequences of such effects are described in note 35.2.2 (a) involving the Company's future exports (accounting policy).

The calculation of “highly probable future exports” is based on the projected exports in the Strategic Plan, as set out in note 4.8. The Company considers only a portion of its projected exports as “highly probable future exports”. When determining future exports as highly probable, and therefore eligible as a hedged item for application of cash flow hedge accounting, the Company considers the effects related to the transition to a low-carbon economy. Carbon prices were not incorporated in such estimates.

Using the prices in the APS and NZE scenarios we carried out a sensitivity analysis to simulate the need to reclassify the foreign exchange gains or losses recorded in equity to the statement of income. Such sensitivity simulated a new future cash flow from exports, changing only the oil price, keeping all other components, variables, assumptions and data unchanged. In such sensitivity, there is no need to reclassify the foreign exchange (gains or losses) recorded in equity to the statement of income in any of the simulated scenarios.

The simulations used to perform such sensitivity analysis, based on Brent prices of the scenarios APS and NZE, are not considered by the Company as the best estimates to determine expected effects of the reclassification of foreign exchange variation recorded in equity to the statement of income.

a.4) Potential effects on the useful lives of PP&E

A transition to a low-carbon economy that is faster than the Company anticipates may reduce the useful life of its assets, which could lead to an increase in annual depreciation, depletion and amortization expenses.

Assets directly related to the production of oil and gas in a contracted area are depleted using the units of production method and depreciated or amortized using the straight-line method. As of December 31, 2023, the carrying amount of these assets in operation in Brazil is US$ 105,498. Out of such assets, the ones that are depreciated or amortized by the straight-line method do not have a useful life ending in or after 2050. As for assets depleted using the units of production method, it is estimated that 4 fields in the State of Bahia, with carrying amount of US$ 234 as of December 31, 2023, have production curves used to estimate its useful lives extending beyond 2050 (based on its proved developed reserves).

As mentioned in item “Transition risk to low carbon economy”, the reference scenario of the Strategic Plan indicates that there will be persistent global demand for oil in the coming decades. Additionally, calculations of expected production and oil and gas reserves in this scenario consider the effects of the transition to a low-carbon economy.

The Company's refining plants consist of 10 refineries in Brazil. Based on the current depreciation rates of the assets in operation applied to the respective carrying amounts at December 31, 2023, which amounts to US$ 11,055, and assuming no additional investment, all refineries would be fully depreciated prior to 2050.

The Company estimates persistent demand for oil products in the coming decades, although decreasing, which should be progressively supplied by models with lower carbon intensity. Thus, the depreciation rates used by the Company for the refining plants are in line with the transition to a low-carbon economy.

The Gas and Energy assets in Brazil, including thermoelectric power plants, are depreciated using the linear method. Based on the current depreciation rates of the assets in operation applied to their respective carrying amounts as of December 31, 2023, totaling US$ 3,004, and assuming no additional investment, these assets would be fully depreciated prior to 2050.

In this context, based on available information, the Company does not foresee significant changes in the useful life of its refineries, assets directly related to oil and gas production and those related to the Gas and Energy arising from the transition to a low-carbon economy. Such assets represent 91% of the Company's total assets in operation.

b)

Physical Risks

The operating conditions of the Company’s assets are subject to physical risks associated with climate change. The variables considered most susceptible to these changes include the patterns of waves, winds and ocean currents in the areas in which the Company operates offshore, as well as the availability of freshwater for our onshore operations.

The Company estimates that the offshore structures in the Brazilian Southeastern basins, which account for the highest percentage of Petrobras’ production (96%), are adequately sized to the expected changes in the patterns of waves, winds and ocean currents in that region.

Regarding the availability of freshwater for the operations of our facilities, the risks related to this subject are monitored, managed and mitigated by the Company. Such risks may arise from various factors that collectively put pressure on water availability, such as population growth, intensification of consumption patterns, inadequate infrastructure, pollution, resource misallocation and climate change.

As a result, the Company's water risk management covers both climatic and non-climatic risks and, based on the Company's assessment, the potential impacts of climate change on the availability of fresh water for our facilities are not representative of all the risks involved.

Consequently, regarding physical risks, as of December 31, 2023, the Company does not foresee that changes caused by climate change will have a material effect on accounting estimates, either from the perspective of meteoceanographic variables or the reduction in freshwater availability.

However, the circumstances that served as the basis for the Company's analyses of climate change scenarios may change, so the approaches used by the Company to conduct these analyses may also be improved over time.

6.	New standards and interpretations

6.1.

New International Financial Reporting Standards not yet adopted

Standard	Description	Effective on
Lease Liability in a Sale and Leaseback - Amendments to IFRS 16	The amendments add requirements that specify that the seller-lessee must subsequently measure the lease liability arising from the transfer of an asset - which meets the requirements of IFRS 15 to be accounted for as a sale - and sale and leaseback, so that no gain or loss is recognized related to the right of use retained in the transaction.	January 1, 2024, retrospective application.
Classification of Liabilities as Current or Non-current / Non-current Liabilities with Covenants- Amendments to IAS 1	The amendments establish that the liability should be classified as current when the entity does not have the right, at the end of the reporting period, to defer the settlement of the liability for at least twelve months after the reporting period.   Among other guidelines, the amendments provide that the classification of a liability is not affected by the likelihood of exercising the right to defer the settlement of the liability. Additionally, according to the amendments, only covenants whose compliance is mandatory before or at the end of the reporting period should affect the classification of a liability as current or non-current.   Additional disclosures are also required by the amendments, including information on non-current liabilities with covenants, whose compliance is mandatory within 12 months after the reporting date	January 1, 2024, retrospective application.
Supplier Finance Arrangements - Amendments to IAS 7 and IFRS 7	The amendments establish the characteristics of finance arrangements involving suppliers and that certain information related to such arrangements must be disclosed in order to enable the assessment of their effects on liabilities, cash flows and exposure to liquidity risk.	January 1, 2024, with specific transition rules.
Lack of Exchangeability - Amendments to IAS 21	The amendments establish that when one currency is not exchangeable for another on the measurement date, the spot exchange rate must be estimated. In addition, they provide guidance on how to assess interchangeability between currencies and how to determine the spot exchange rate when interchangeability is absent.   When the spot exchange rate is estimated because a currency is not exchangeable for another currency, information must be disclosed to allow the understanding of how the currency not exchangeable for another currency affects, or is expected to affect, the statements of income, the statement of financial position and the statements of cash flows.	January 1, 2025, with specific transition rules.

 

 

Regarding the amendments to IFRS 16 and to IAS 1, effective as of January 1, 2024, according to the assessment made, the Company estimates that there will be no significant impact with the initial application on its consolidated financial statements. In relation to the amendments to IAS 7 and IFRS 7, the Company expects additional disclosure.

As for the amendment that will be effective as of January 1, 2025, the Company is assessing the impacts that it will have on the financial statements.

7.	Capital Management

The Company’s objective in its capital management is to maintain its capital structure at an adequate level in order to continue as a going concern, maximizing value to shareholders and investors. In 2023 and 2022, its main source of funding was cash provided by its operating activities.

The financial strategy of the Strategic Plan 2024-2028 is focused on:

•

indebtedness control;

•

investments and business decisions respecting the ideal capital structure;

•

solid governance in decision-making processes ensuring profitability, rationality and value creation for all stakeholders; and

•

distribution of value created through dividends and share repurchase.

The target for the gross debt (composed of current and non-current finance debt and lease liability) is to be maintained below US$ 65,000 and the reference level for Adjusted Cash and cash equivalents is US$ 8,000 (which is composed of Cash and cash equivalents, and investments in securities in domestic and international markets that have high liquidity, i.e., convertible into cash within 3 months, even if maturity is longer than 12 months, held for the purpose of complying with cash commitments).

As of December 31, 2023, gross debt increased to US$ 62,600, from US$ 53,799 as of December 31, 2022, remaining within the range defined in the Company’s Strategic Plan.

8.	Cash and cash equivalents and marketable securities

8.1.

Cash and cash equivalents

They include cash, available bank deposits and short-term financial investments with high liquidity, which meet the definition of cash equivalents.

	12.31.2023	12.31.2022
Cash at bank and in hand	103	216
Short-term financial investments
- In Brazil
Brazilian interbank deposit rate investment funds and other short-term deposits	1,742	2,763
Other investment funds	279	244
	2,021	3,007
- Abroad
Time deposits	7,737	2,388
Automatic investing accounts and interest checking accounts	2,852	2,365
Other financial investments	14	20
	10,603	4,773
Total short-term financial investments	12,624	7,780
Total cash and cash equivalents	12,727	7,996

 

 

Short-term financial investments in Brazil primarily consist of investments in funds holding Brazilian Federal Government Bonds that can be redeemed immediately, as well as reverse repurchase agreements that mature within three months as of the date of their acquisition. Short-term financial investments abroad comprise time deposits that mature in three months or less from the date of their acquisition, highly-liquid automatic investment accounts, interest checking accounts and other short-term fixed income instruments.

The main resources constituted were substantially provided by cash provided by operating activities of US$ 43,212, proceeds from disposal of assets - divestment of US$ 3,606, proceeds from finance debt of US$ 2,210 and financial compensation from co-participation agreements of US$ 391.

The main use of these funds in 2023 were for payment of dividends and share repurchase program of US$ 20,454, repayment of principal and interests related to finance debt and repayment of lease liability, amounting US$ 12,457, as well as for acquisition of PP&E and intangible assets in the amount of US$ 12,114.

Accounting policy for cash and cash equivalents

Cash and cash equivalents comprise cash on hand, term deposits with banks and short-term highly-liquid financial investments that are readily convertible to known amounts of cash, are subject to insignificant risk of changes in value and have a maturity of three months or less from the date of acquisition.

8.2.

Marketable securities

			12.31.2023			12.31.2022
	In Brazil	Abroad	Total	In Brazil	Abroad	Total
Fair value through profit or loss	926	−	926	713	−	713
Amortized cost - Bank Deposit Certificates and time deposits	4,249	−	4,249	2,548	1,026	3,574
Amortized cost - Others	53	−	53	50	−	50
Total	5,228	−	5,228	3,311	1,026	4,337
Current	2,819	−	2,819	1,747	1,026	2,773
Non-current	2,409	−	2,409	1,564	−	1,564

 

 

Marketable securities classified as fair value through profit or loss refer mainly to investments in Brazilian Federal Government Bonds (amounts determined by level 1 of the fair value hierarchy). These financial investments have maturities of more than three months.

Securities classified as amortized cost refer to investments in Brazil in post-fixed Bank Deposit Certificates with daily liquidity, with maturities between one and two years, and to investments abroad in time deposits with maturities of more than three months from the contracting date.

Accounting policy for marketable securities

The amounts invested in operations with terms of more than three months, as from the date of the agreement, are initially measured at fair value and subsequently according to their respective classifications, which are based on the way in which these funds are managed and their features of contractual cash flows:

·

Amortized cost – financial assets that give rise, on specified dates, to cash flows represented exclusively by payments of principal and interest on the outstanding principal amount, the purpose of which is to receive its contractual cash flows. They are presented in current and in non-current asset according to their maturity term. Interest income from these investments is calculated using the effective interest rate method.

·

Fair value through profit or loss – financial assets whose purpose is to receive from its sale. They are presented in current assets due to the expectation of realization within 12 months of the reporting date.

9.	Sales revenues

9.1.

Revenues from contracts with customers

As an integrated energy company, revenues from contracts with customers derive from different products sold by the Company’s operating segments, taking into consideration specific characteristics of the markets where they operate. For additional information about the operating segments of the Company, its activities and its respective products sold, see note 13.

The determination of transaction prices derives from methodologies and policies based on the parameters of these markets, reflecting operating risks, level of market share, changes in exchange rates and international commodity prices, including Brent oil prices, oil products such as diesel and gasoline, and the Henry Hub Index.

 

	2023	2022	2021
Diesel	32,260	40,149	24,236
Gasoline	14,309	16,175	11,910
Liquefied petroleum gas	3,506	5,121	4,491
Jet fuel	5,015	5,423	2,271
Naphtha	1,837	2,396	1,699
Fuel oil (including bunker fuel)	1,158	1,411	1,775
Other oil products	4,428	5,536	4,261
Subtotal oil products	62,513	76,211	50,643
Natural gas	5,632	7,673	5,884
Crude oil	5,475	7,719	671
Renewables and nitrogen products	94	283	40
Breakage	860	669	243
Electricity	657	694	2,902
Services, agency and others	1,059	1,043	808
Domestic market	76,290	94,292	61,191
Exports	25,012	27,497	21,491
Crude oil	18,447	19,332	14,942
Fuel oil (including bunker fuel)	5,114	7,399	5,480
Other oil products and other products	1,451	766	1,069
Sales abroad (1)	1,107	2,685	1,284
Foreign market	26,119	30,182	22,775
Sales revenues	102,409	124,474	83,966
(1) Sales revenues from operations outside of Brazil, including trading and excluding exports.

 

 

As of December 31, 2023, the composition of sales revenues by shipping destination is presented as follows:

	2023	2022	2021
Domestic market	76,290	94,292	61,191
China	7,232	6,389	7,053
Americas (except United States)	4,846	7,166	4,702
Europe	5,534	5,932	3,110
Asia (except China and Singapore)	1,447	1,505	1,671
United States	3,924	4,914	2,162
Singapore	3,063	4,271	3,913
Others	73	5	164
Foreign market	26,119	30,182	22,775
Sales revenues	102,409	124,474	83,966

 

 

In 2023, sales to two clients of the refining, transportation and marketing segment represented individually 16% and 11% of the Company’s sales revenues; in 2022, sales to two clients of the same segment individually represented 15% and 11% of the Company’s sales revenues; and in 2021 one client of the same segment individually represented 10% of the Company’s sales revenues. 

9.2.

Remaining performance obligations

The Company is party to sales contracts signed until December 31, 2023 with original expected duration of more than 1 year, which define the volume and timing of goods or services to be delivered during the term of the contract, and the payment terms for these future sales.

The estimated remaining values of these contracts in 2023 presented below are based on the contractually agreed future sales volumes, as well as prices prevailing at December 31, 2023 or practiced in recent sales reflecting more directly observable information:

 

	Expected recognition within 1 year	Expected recognition after 1 year	Total
Domestic market
Gasoline	12,161	178	12,339
Diesel	27,325	-	27,325
Natural gas	7,715	38,986	46,701
Liquefied petroleum gas	3,120	-	3,120
Services and others	740	3,607	4,347
Naphtha	1,497	1,497	2,994
Electricity	529	4,919	5,448
Other oil products	3,013	3,756	6,769
Jet fuel	1,335	-	1,335
Foreign market
Exports	2,732	5,337	8,069
Total	60,167	58,280	118,447

 

 

Revenues are recognized once goods are transferred and services are provided to the customers and their measurement and timing of recognition will be subject to future demands, changes in commodities prices, exchange rates and other market factors.

The table above does not include information on contracts with original expected duration of less than one year, such as spot-market contracts, variable considerations which are constrained, and information on contracts only establishing general terms and conditions (Master Agreements), for which volumes and prices will only be defined in subsequent contracts.

In addition, electricity sales are mainly driven by demands to generate electricity from thermoelectric power plants, as and when requested by the Brazilian National Electric System Operator (ONS). These requests are substantially affected by Brazilian hydrological conditions. Thus, the table above presents mainly fixed amounts for the electricity to be available to customers in these operations.

9.3.

Contract liabilities

The balance of contract liabilities carried on the statement of financial position in 2023 amounted to US$ 115 (US$ 48 in 2022). This amount is classified as other current liabilities and primarily comprises advances from customers in ship and take or pay contracts to be recognized as revenue based on future sales of natural gas or following the non-exercise of the right by the customer.

Accounting policy for revenues

The Company evaluates contracts with customers for the sale of oil and oil products, natural gas, electricity, services and other products, which will be subject to revenue recognition, and identifies the distinct goods and services promised in each of them.

Sales revenues are recognized when control is transferred to the client, which usually occurs upon delivery of the product or when the service is provided. At this moment, the company satisfies the performance obligation.

Performance obligations are considered to be promises to transfer to the client: (i) good or service (or group of goods or services) that is distinct; and (ii) a series of distinct goods or services that have the same characteristics or are substantially the same and that have the same pattern of transfer to the client.

Revenue is measured based on the amount of consideration to which the Company expects to be entitled in exchange for transfers of promised goods or services to the customer, excluding amounts collected on behalf of third parties. Transaction prices are based on contractually stated prices, which reflect the Company's pricing methodologies and policies based on market parameters.

Invoicing occurs in periods very close to deliveries and rendering of services, therefore, significant changes in transaction prices are not expected to be recognized in revenues for periods subsequent to satisfaction of the performance obligation, except for some exports in which final price formation occurs after the transfer of control of the products and are subject to the variation in the value of the commodity.

Sales are carried out in short terms of receipt, thus there are no significant financing components.

10.	Costs and expenses by nature

10.1.

Cost of sales

	2023	2022	2021
Raw material, products for resale, materials and third-party services (1)	(23,858)	(32,354)	(20,869)
Depreciation, depletion and amortization	(10,779)	(10,514)	(9,277)
Production taxes	(12,108)	(14,953)	(11,136)
Employee compensation	(1,690)	(1,665)	(1,882)
Total	(48,435)	(59,486)	(43,164)
(1) It Includes short-term leases and inventory turnover.

 

 

10.2.

Selling expenses

	2023	2022	2021
Materials, third-party services, freight, rent and other related costs	(4,296)	(3,987)	(3,542)
Depreciation, depletion and amortization	(609)	(789)	(610)
Allowance for expected credit losses	(22)	(58)	12
Employee compensation	(111)	(97)	(89)
Total	(5,038)	(4,931)	(4,229)

 

 

10.3.

General and administrative expenses

	2023	2022	2021
Employee compensation	(1,036)	(865)	(834)
Materials, third-party services, rent and other related costs	(435)	(362)	(256)
Depreciation, depletion and amortization	(123)	(105)	(86)
Total	(1,594)	(1,332)	(1,176)

 

11.	Other income and expenses, net

	2023	2022	2021
Stoppages for asset maintenance and pre-operating expenses	(2,205)	(1,834)	(1,362)
Gains (losses) on decommissioning of returned/abandoned areas	(1,195)	(225)	99
Pension and medical benefits - retirees (1)	(1,172)	(1,015)	(1,467)
Losses with legal, administrative and arbitration proceedings	(797)	(1,362)	(740)
Profit sharing	(595)	(131)	(125)
Variable compensation programs	(416)	(547)	(469)
Compensation for the termination of vessel charter agreements (2)	(331)	(13)	(9)
Collective bargaining agreement	(217)	-	-
Expenses with contractual fines received	(199)	(91)	(57)
Operating expenses with thermoelectric power plants	(189)	(150)	(88)
Institutional relations and cultural projects	(156)	(103)	(96)
Gains (losses) with commodities derivatives	11	(256)	(79)
Amounts recovered from Lava Jato investigation	109	96	235
Results of non-core activities	170	168	170
Ship/take or pay agreements and fines imposed to suppliers	238	105	96
Fines imposed on suppliers	239	228	163
Results from co-participation agreements in bid areas (3)	284	4,286	631
Government grants	315	471	154
Early termination and changes to cash flow estimates of leases	415	629	545
Reimbursements from E&P partnership operations	571	683	485
Results on disposal/write-offs of assets	1,295	1,144	1,941
Others	(206)	(261)	626
Total	(4,031)	1,822	653
(1) In 2022, this includes US$ 67 referring to the payment of a contribution as provided for in the Pre-70 Term of Financial Commitment (TFC) for the administrative funding of the PPSP-R Pre-70 and PPSP-NR Pre-70 pension plans.
(2) It includes, in 2023, expenses with compensation for the termination of a vessel charter agreement in the amount of US$ 317.
(3) In 2022, it mainly refers to income with the results of the co-participation agreements related to the transfer of rights surplus of Sépia and Atapu fields. In 2021, it refers to the agreement of the Búzios field.

 

12.	Net finance income (expense)

	2023	2022	2021
Finance income	2,169	1,832	821
Income from investments and marketable securities (Government Bonds)	1,657	1,159	315
Other finance income	512	673	506
Finance expenses	(3,922)	(3,500)	(5,150)
Interest on finance debt	(2,264)	(2,363)	(2,870)
Unwinding of discount on lease liability	(1,785)	(1,340)	(1,220)
Discount and premium on repurchase of debt securities	(4)	(121)	(1,102)
Capitalized borrowing costs	1,290	1,032	976
Unwinding of discount on the provision for decommissioning costs	(857)	(519)	(761)
Other finance expenses	(302)	(189)	(173)
Foreign exchange gains (losses) and indexation charges	(580)	(2,172)	(6,637)
Foreign exchange gains (losses) (1)	2,268	1,022	(2,737)
Reclassification of hedge accounting to the Statement of Income (1)	(3,763)	(4,871)	(4,585)
Indexation to the Selic interest rate of anticipated dividends and dividends payable (2)	(299)	994	108
Legal agreement with Eletrobras - compulsory loans (3)	236	−	−
Recoverable taxes inflation indexation income	204	86	518
Other foreign exchange gains and indexation charges, net	774	597	59
Total	(2,333)	(3,840)	(10,966)
(1) For more information, see notes 35.2a and 35.2c.
(2) In 2023, it refers to the income on the indexation to the Selic interest rate of paid anticipated dividends, in the amount of US$ 215 (US$ 1,293 in 2022 and US$ 121 in 2021), and to the expense on the indexation to the Selic interest rate on dividends payable, in the amount of US$ 514 (US$ 299 in 2022 and US$ 13 in 2021).
(3) For more information, see note 19.6.

 

13.	Information by operating segment

On November 23, 2023, the Board of Directors approved, in the context of the Strategic Plan 2024-2028, a new approach in relation to capital expenditures that will be made by the Company, changing the vision of the segment from “Gas & Power” to “Gas and Low Carbon Energies”, in addition to new strategic business drivers for:

·

Biofuels: previously presented in Corporate and other businesses, they are now integrated in the Gas and Low Carbon Energies (G&LCE) segment;

·

Fertilizers: previously presented in Gas & Power, they are now integrated in the Refining, Transportation and Marketing segment.

As of December 31, 2023, the presentation of information by operation segment reflects the updated management model used by the Board of Executive Officers (Chief Operating Decision Maker - CODM) to make decisions regarding resource allocation and performance evaluation.

In this context, the information by segment for the years 2022 and 2021 were not reclassified for comparability purposes due to the fact that the total of assets and statement of income balances involved are immaterial.

13.1.

Net income by operating segment

Consolidated statement of income by operating segment
2023
	Exploration and Production (E&P)	Refining, Transportation & Marketing (RT&M)	Gas and Low Carbon Energies (G&LCE)	Corporate and other businesses	Eliminations	Total
Sales revenues	66,880	94,868	11,109	365	(70,813)	102,409
Intersegments	66,113	1,404	3,285	11	(70,813)	−
Third parties	767	93,464	7,824	354	-	102,409
Cost of sales	(27,239)	(85,699)	(5,685)	(370)	70,558	(48,435)
Gross profit (loss)	39,641	9,169	5,424	(5)	(255)	53,974
Income (expenses)	(5,615)	(4,086)	(3,384)	(2,857)	1	(15,941)
Selling expenses	(12)	(2,156)	(2,838)	(33)	1	(5,038)
General and administrative expenses	(74)	(327)	(80)	(1,113)	-	(1,594)
Exploration costs	(982)	-	-	-	-	(982)
Research and development expenses	(569)	(16)	(3)	(138)	-	(726)
Other taxes	(454)	(27)	(49)	(360)	-	(890)
Impairment (losses) reversals, net	(2,105)	(524)	(81)	30	-	(2,680)
Other income and expenses, net	(1,419)	(1,036)	(333)	(1,243)	-	(4,031)
Income (loss) before net finance income (expense), results of equity-accounted investments and income taxes	34,026	5,083	2,040	(2,862)	(254)	38,033
Net finance income (expense)	-	-	-	(2,333)	-	(2,333)
Results of equity-accounted investments	(7)	(318)	10	11	-	(304)
Net income / (loss) before income taxes	34,019	4,765	2,050	(5,184)	(254)	35,396
Income taxes	(11,571)	(1,729)	(693)	3,506	86	(10,401)
Net income (loss) for the year	22,448	3,036	1,357	(1,678)	(168)	24,995
Attributable to:
Shareholders of Petrobras	22,453	3,036	1,286	(1,723)	(168)	24,884
Non-controlling interests	(5)	-	71	45	-	111

 

 

 

 

2022
	Exploration and Production (E&P)	Refining, Transportation & Marketing (RT&M)	Gas and Low Carbon Energies (G&LCE)	Corporate and other businesses	Eliminations	Total
Sales revenues	77,890	113,531	15,068	511	(82,526)	124,474
Intersegments	76,579	1,950	3,991	6	(82,526)	−
Third parties	1,311	111,581	11,077	505	-	124,474
Cost of sales	(30,465)	(99,154)	(10,518)	(522)	81,173	(59,486)
Gross profit (loss)	47,425	14,377	4,550	(11)	(1,353)	64,988
Income (expenses)	907	(3,132)	(2,965)	(2,671)	(13)	(7,874)
Selling expenses	(22)	(1,841)	(2,979)	(76)	(13)	(4,931)
General and administrative expenses	(46)	(275)	(62)	(949)	-	(1,332)
Exploration costs	(887)	-	-	-	-	(887)
Research and development expenses	(678)	(6)	(5)	(103)	-	(792)
Other taxes	(79)	(31)	(44)	(285)	-	(439)
Impairment (losses) reversals, net	(1,218)	(97)	1	(1)	-	(1,315)
Other income and expenses, net	3,837	(882)	124	(1,257)	-	1,822
Income (loss) before net finance income (expense), results of equity-accounted investments and income taxes	48,332	11,245	1,585	(2,682)	(1,366)	57,114
Net finance expense	-	-	-	(3,840)	-	(3,840)
Results of equity-accounted investments	170	3	83	(5)	-	251
Net income / (loss) before income taxes	48,502	11,248	1,668	(6,527)	(1,366)	53,525
Income taxes	(16,433)	(3,822)	(540)	3,559	466	(16,770)
Net income (loss) for the year	32,069	7,426	1,128	(2,968)	(900)	36,755
Attributable to:
Shareholders of Petrobras	32,073	7,426	1,038	(3,014)	(900)	36,623
Non-controlling interests	(4)	-	90	46	-	132

 

 

 

 

	2021
	Exploration and Production (E&P)	Refining, Transportation & Marketing (RT&M)	Gas and Low Carbon Energies (G&LCE)	Corporate and other businesses	Eliminations	Total
Sales revenues	55,584	74,524	12,051	504	(58,697)	83,966
Intersegments	54,479	1,416	2,564	238	(58,697)	−
Third parties	1,105	73,108	9,487	266	-	83,966
Cost of sales	(23,673)	(65,620)	(9,494)	(503)	56,126	(43,164)
Gross profit (loss)	31,911	8,904	2,557	1	(2,571)	40,802
Income (expenses)	3,240	(1,805)	(2,890)	(1,741)	(22)	(3,218)
Selling expenses	-	(1,539)	(2,668)	-	(22)	(4,229)
General and administrative expenses	(152)	(245)	(73)	(706)	-	(1,176)
Exploration costs	(687)	-	-	-	-	(687)
Research and development expenses	(415)	(11)	(25)	(112)	-	(563)
Other taxes	(192)	(122)	(38)	(54)	-	(406)
Impairment (losses) reversals, net	3,107	289	(208)	2	-	3,190
Other income and expenses, net	1,579	(177)	122	(871)	-	653
Income (loss) before net finance income (expense), results of equity-accounted investments and income taxes	35,151	7,099	(333)	(1,740)	(2,593)	37,584
Net finance expense	-	-	-	(10,966)	-	(10,966)
Results of equity-accounted investments	119	941	98	449	-	1,607
Net income / (loss) before income taxes	35,270	8,040	(235)	(12,257)	(2,593)	28,225
Income taxes	(11,949)	(2,415)	113	5,129	883	(8,239)
Net income (loss) for the year	23,321	5,625	(122)	(7,128)	(1,710)	19,986
Attributable to:
Shareholders of Petrobras	23,324	5,625	(219)	(7,145)	(1,710)	19,875
Non-controlling interests	(3)	-	97	17	-	111

 

 

 

The amount of depreciation, depletion and amortization by segment is set forth as follows:

	Exploration and Production (E&P)	Refining, Transportation & Marketing (RT&M)	Gas and Low Carbon Energies (G&LCE)	Corporate and other businesses	Total
2023	10,230	2,410	525	115	13,280
2022	10,415	2,248	448	107	13,218
2021	9,005	2,167	430	93	11,695

 

 

13.2.

Assets by operating segment

	Exploration and Production (E&P)	Refining, Transportation & Marketing (RT&M)	Gas and Low Carbon Energies (G&LCE)	Corporate and other business	Elimina-tions	Total
Consolidated assets by operating segment - 12.31.2023
Current assets	2,804	11,002	370	23,547	(5,278)	32,445
Non-current assets	136,064	23,800	6,406	18,352	−	184,622
Long-term receivables	9,028	2,068	83	15,619	−	26,798
Investments	344	811	145	58	−	1,358
Property, plant and equipment	124,254	20,786	6,101	2,283	−	153,424
Operating assets	108,405	18,128	3,605	1,770	−	131,908
Under construction	15,849	2,658	2,496	513	−	21,516
Intangible assets	2,438	135	77	392	−	3,042
Total Assets	138,868	34,802	6,776	41,899	(5,278)	217,067
Consolidated assets by operating segment - 12.31.2022
Current assets	5,224	12,035	391	18,864	(5,264)	31,250
Non-current assets	111,110	22,396	7,193	15,242	−	155,941
Long-term receivables	6,351	1,811	94	12,964	−	21,220
Investments	379	977	173	37	−	1,566
Property, plant and equipment	101,875	19,496	6,851	1,947	−	130,169
Operating assets	92,087	16,851	4,808	1,585	−	115,331
Under construction	9,788	2,645	2,043	362	−	14,838
Intangible assets	2,505	112	75	294	−	2,986
Total Assets	116,334	34,431	7,584	34,106	(5,264)	187,191

 

 

Accounting policy for operating segments

The information related to the Company’s operating segments is prepared based on available financial information directly attributable to each segment, or items that can be allocated to each segment on a reasonable basis. This information is presented by business activity, as used by the Company’s Board of Executive Officers (Chief Operating Decision Maker – CODM) in the decision-making process of resource allocation and performance evaluation.

The measurement of segment results includes transactions carried out with third parties, including associates and joint ventures, as well as transactions between operating segments. Transfers between operating segments are recognized at internal transfer prices derived from methodologies that considers market parameters and are eliminated only to provide reconciliations to the consolidated financial statements.

The Company's business segments disclosed separately are:

Exploration and Production (E&P): this segment covers the activities of exploration, development and production of crude oil, NGL (natural gas liquid) and natural gas in Brazil and abroad, for the primary purpose of supplying its domestic refineries. The E&P segment also operates through partnerships with other companies and includes holding interest in foreign entities operating in this segment.

As an energy Company with a focus on oil and gas, intersegment sales revenue refers mainly to oil transfers to the Refining, Transportation and Marketing segment, aiming to supply the Company's refineries and meet the domestic demand for oil products. These transactions are measured by internal transfer prices based on international oil prices and their respective exchange rate impacts, taking into account the specific characteristics of the transferred oil stream.

In addition, the E&P segment revenues include transfers of natural gas to the natural gas processing plants within Gas and Low Carbon Energies segment. These transactions are measured at internal transfer prices based on the international prices of this commodity.

Revenue from sales to third parties mainly reflects services rendered relating to E&P activities, sales of the E&P’s natural gas processing plants, as well as the oil and natural gas operations carried out by subsidiaries abroad.

Refining, Transportation and Marketing (RT&M): this segment covers the refining, logistics, transport, acquisition and exports of crude oil, as well as trading of oil products, in Brazil and abroad. This segment also includes the petrochemical operations (which comprehends holding interests in petrochemical companies in Brazil), and fertilizer production.

This segment carries out the acquisition of crude oil from the E&P segment, imports oil for refinery slate, and acquires oil products in international markets taking advantage of the existing price differentials between the cost of processing domestic oil and that of importing oil products. This segment also performs the acquisition of natural gas from the G&LCE segment.

Intersegment revenues primarily reflect the sale of oil products to the distribution business at market prices and the operations for the G&LCE and E&P segments at internal transfer price.

Revenues from sales to third parties primarily reflect the trading of oil products in Brazil and the export and trade of oil and oil products by foreign subsidiaries.

Gas and Low Carbon Energies (G&LCE): this segment covers the activities of logistic and trading of natural gas and electricity, the transportation and trading of liquefied natural gas (LNG), the generation of electricity by means of thermoelectric power plants, as well as natural gas processing. It also includes renewable energy businesses, low carbon services (carbon capture, utilization and storage) and the production of biodiesel and its co-products.

Intersegment revenues primarily reflect the transfers of natural gas processed, liquefied petroleum gas (LPG) and NGL to the RT&M segment. These transactions are measured at internal transfer prices.

This segment purchases national natural gas from the E&P segment, from partners and third parties, imports natural gas from Bolivia and LNG to meet national demand.

Revenues from sales to third parties primarily reflect natural gas processed to distributors and to free consumers, as well as generation and trading of electricity.

Corporate and other businesses: comprise items that cannot be attributed to business segments, including those with corporate characteristics, in addition to distribution business. Corporate items mainly include those related to corporate financial management, trade and other receivables, allowance for credit losses, gains (losses) with derivatives (except those with commodity derivatives included in their respective segments), corporate overhead and other expenses, including actuarial expenses related to pension and health care plans for beneficiaries. Other businesses include the distribution of oil products abroad (South America). In 2021, the results of other businesses included the equity interest in the associate Vibra Energia, formerly Petrobras Distribuidora, until the date of sale of the remaining interest in this associate, which took place in July 2021.

14.	Trade and other receivables

14.1.

Trade and other receivables

	12.31.2023	12.31.2022
Receivables from contracts with customers
Third parties	6,038	5,210
Related parties
Investees (note 36.1)	140	93
Subtotal	6,178	5,303
Other trade  receivables
Third parties
Receivables from divestments and Transfer of Rights Agreement	2,162	1,922
Lease receivables	352	394
Other receivables	627	765
Related parties
Petroleum and alcohol accounts - receivables from Brazilian Federal Government	278	602
Subtotal	3,419	3,683
Total trade and other receivables, before ECL	9,597	8,986
Expected credit losses (ECL) - Third parties	(1,613)	(1,533)
Expected credit losses (ECL) - Related parties	(2)	(3)
Total trade and other receivables	7,982	7,450
Current	6,135	5,010
Non-current	1,847	2,440

 

 

Trade and other receivables are generally classified as measured at amortized cost, except for receivables with final prices linked to changes in commodity price after their transfer of control, which are classified as measured at fair value through profit or loss, amounting to US$ 503 as of December 31, 2023 (US$ 470 as of December 31, 2022).

The balance of receivables from divestments is mainly related to the Earn Out of the Atapu and Sépia fields, totaling US$ 611(US$ 693 in 2022), from the sale of the Roncador field for US$ 360 (US$ 393 in 2022), the Carmópolis group of fields for US$ 296 (US$ 275 in 2022), and the Potiguar group of fields for US$ 265.

On September 8, 2023, the Company received US$ 362, net of withholding income taxes, relating to the first installment of Petroleum and Alcohol Accounts. The second and final installment in the amount of US$ 278 is still in a judicial account and awaits court clearance to work as a guarantee in a tax enforcement proceeding in the 11th Execution Court.

In 2023, the average term for trade receivables from third parties in the domestic market is approximately 2 days (same term in 2022) for the sale of derivatives and 20 to 27 days for the sale of crude oil (same term as in 2022). Fuel oil exports have an average receipt term between 11 and 14 days, while oil exports have a term between 8 and 12 days (in 2022, exports have average terms ranging from 12 days to 26 days for fuel oil and from 7 to 16 days for oil).

14.2.

Aging of trade and other receivables – third parties

	12.31.2023		12.31.2022
	Trade and other receivables	Expected credit losses	Trade and other receivables	Expected credit losses
Current	6,948	(34)	6,474	(39)
Overdue:
1-90 days (1)	472	(43)	189	(48)
91-180 days	19	(10)	30	(27)
181-365 days	63	(57)	63	(51)
More than 365 days	1,677	(1,469)	1,535	(1,368)
Total	9,179	(1,613)	8,291	(1,533)
(1) On January 10, 2024, Petrobras received US$ 298 from Carmo Energy as the last installment relating to the sale of the Carmópolis cluster, due on December 20, 2023.

 

 

14.3.

Changes in provision for expected credit losses – third parties and related parties

	31.12.2023	31.12.2022
Opening balance	1,536	1,448
Additions	170	136
Write-offs	(66)	(21)
Reversals	(94)	(81)
Translation adjustment	69	54
Closing balance	1,615	1,536
Current	285	245
Non-current	1,330	1,291

 

 

Accounting policy for trade and other receivables

Trade and other receivables are generally classified at amortized cost, except for certain receivables classified at fair value through profit or loss, whose cash flows are distinct from the receipt of principal and interest, including receivables with final prices linked to changes in commodity price after their transfer of control.

When the Company is the lessor in a finance lease, a receivable is recognized at the amount of the net investment in the lease, consisting of the lease payments receivable and any unguaranteed residual value accruing to the Company, discounted at the interest rate implicit in the lease.

The Company measures expected credit losses (ECL) for short-term trade receivables using a provision matrix which is based on historical observed default rates adjusted by current and forward-looking information when applicable and available without undue cost or effort.

ECL is the weighted average of historical credit losses with the respective default risks, which may occur according to the weightings. The credit loss on a financial asset is measured by the difference between all contractual cash flows due to the Company and all cash flows the Company expects to receive, discounted at the original effective interest rate.

The Company measures the allowance for ECL of other trade receivables based on their 12-month expected credit losses unless their credit risk increases significantly since their initial recognition, in which case the allowance is based on their lifetime ECL.

When determining whether there has been a significant increase in credit risk, the Company compares the risk of default on initial recognition and at the reporting date.

Regardless of the assessment of significant increase in credit risk, a delinquency period of 30 days past due triggers the definition of significant increase in credit risk on a financial asset, unless otherwise demonstrated by reasonable and supportable information.

The Company assumes that the credit risk on the trade receivable has not increased significantly since initial recognition if the receivable is considered to have low credit risk at the reporting date. Low credit risk is determined based on external credit ratings or internal methodologies.

In the absence of controversy or other issues that may result in the suspension of collection, the Company assumes that a default occurs whenever the counterparty does not comply with the legal obligation to pay its debts when due or, depending on the instrument, when it is at least 90 days past due.

15.	Inventories

	12.31.2023	12.31.2022
Crude oil	3,375	3,738
Oil products	2,196	3,278
Intermediate products	635	587
Natural gas and Liquefied Natural Gas (LNG)	78	135
Biofuels	13	14
Fertilizers	1	4
Total products	6,298	7,756
Materials, supplies and others	1,383	1,023
Total	7,681	8,779

 

 

Crude oil and LNG inventories can be traded or used for production of oil products.

Intermediate products are those product streams that have been through at least one of the refining processes, but still need further treatment, processing or converting to be available for sale.

Biofuels mainly include ethanol and biodiesel inventories.

Materials, supplies and others mainly comprise production supplies and operating materials used in the operations of the Company, stated at the average purchase cost, not exceeding replacement cost.

In 2023, the Company recognized a US$ 7 reversal of cost of sales, adjusting inventories to net realizable value (a US$ 11 loss within cost of sales in 2022), primarily due to changes in international prices of crude oil and oil products.

At December 31, 2023, the Company had pledged crude oil and oil products volumes as collateral for the Term of Financial Commitment (TFC) related to Pension Plans PPSP-R, PPSP-R Pre-70 and PPSP-NR Pre-70 signed by Petrobras and Fundação Petrobras de Seguridade Social – Petros Foundation in 2008, in the estimated amount of US$ 986.

Accounting policy for inventories

Inventories are determined by the weighted average cost method adjusted to the net realizable value when it is lower than its carrying amount.

Net realizable value is the estimated selling price of inventory in the ordinary course of business, less estimated cost of completion and estimated expenses to complete its sale, considering the purpose for which the inventories are held. Inventories with identifiable sales contracts have a net realizable value based on the contracted price, as, for example, in offshore operations (without physical tanking, with loading onto the ship and direct unloading at the customer) or auctions. Other items in inventory have a net realizable value based on general selling prices, considering the most reliable evidence available at the time of the estimate.

The net realizable value of inventories is determined by grouping similar items with the same characteristic or purpose. Changes in sales prices after the reporting date of the financial statements are considered in the calculation of the net realizable value if they confirm the conditions existing on that reporting date.

16.	Trade payables

	12.31.2023	12.31.2022
Third parties in Brazil	3,624	3,497
Third parties abroad	1,176	1,935
Related parties (note 36.1)	13	32
Total	4,813	5,464

 

 

Forfaiting

The Company has a program to encourage the development of the oil and gas production chain called “Mais Valor” (More Value), operated by a partner company on a 100% digital platform.

By using this platform, the suppliers who want to anticipate their receivables may launch a reverse auction, in which the winner is the financial institution which offers the lowest discount rate. The financial institution becomes the creditor of invoices advanced by the supplier, and Petrobras pays the invoices on the same date and under the conditions originally agreed with the supplier.

Invoices are advanced in the “Mais Valor” program exclusively at the discretion of the suppliers and do not change the terms, prices and commercial conditions contracted by Petrobras with such suppliers, as well as it does not add financial charges to the Company, therefore, the classification is maintained as Trade payables in Statements of Cash Flows (Cash flows from operating activities).

As of December 31, 2023, the balance advanced by suppliers, within the scope of the program, is US$ 110 (US$ 130 as of December 31, 2022) and has a payment term from 7 to 92 days and a weighted average term of 57 days (24 days as of December 31, 2022), after the contracted commercial conditions have been met.

17.

Taxes

17.1.

Income taxes

	Current assets		Current liabilities		Non-current liabilities
	12.31.2023	12.31.2022	12.31.2023	12.31.2022	12.31.2023	12.31.2022
Taxes in Brazil
Income taxes	199	160	989	2,505	−	−
Income taxes - Tax settlement programs	−	−	58	50	299	302
	199	160	1,047	2,555	299	302
Taxes abroad	19	5	253	328	−	−
Total	218	165	1,300	2,883	299	302

 

 

Income taxes are calculated based on a 15% rate plus additional 10% on the taxable income for the IRPJ, and 9% on taxable income for the CSLL, considering the offset of tax loss carryforwards and negative basis of the CSLL, limited to 30% of the taxable income of the year. As of the 2015, due to the release of Law No. 12,973/2014, the net income obtained abroad by a direct or indirect subsidiary, or by an associated company, adjusted by dividends and by the result of equity accounted investments, multiplied by the income taxes rates existing in Brazil, comprise the income taxes expenses.

Income taxes assets refer mainly to tax credits resulting from the monthly process for estimation and payment of income taxes, in addition to the negative balance of IRPJ and CSLL related to 2017, 2018, 2019 and 2021. Income taxes within current liabilities refer to the current portion of IRPJ and CSLL to be paid.

Tax settlement programs amounts relate mainly to a notice of deficiency issued by the Brazilian Federal Revenue Service due to the treatment of expenses arising from the Terms of Financial Commitment (TFC) as deductible in determining taxable profit for the calculation of income taxes. The payment term is 145 monthly installments, indexed by the Selic interest rate, as of January 2018.

Reconciliation between statutory income tax rate and effective income tax rate

The following table provides the reconciliation of Brazilian statutory tax rate to the Company’s effective rate on income before income taxes:

	2023	2022	2021
Net income before income taxes	35,396	53,525	28,225
Nominal income taxes computed based on Brazilian statutory corporate tax rates (34%)	(12,036)	(18,197)	(9,597)
Adjustments to arrive at the effective tax rate:
Tax benefits from the deduction of interest on capital distributions	1,329	1,234	843
Different jurisdictional tax rates for companies abroad	579	822	296
Brazilian income taxes on income of companies incorporated outside Brazil (1)	(530)	(763)	(546)
Tax incentives	303	187	50
Tax loss carryforwards (unrecognized tax losses)	23	221	59
Non-taxable income (non-deductible expenses), net (2)	322	(15)	234
Post-employment benefits	(348)	(394)	(802)
Results of equity-accounted investments in Brazil and abroad	(88)	87	318
Non-incidence of income taxes on indexation (SELIC interest rate) of undue paid taxes	54	33	903
Others	(9)	15	3
Income taxes	(10,401)	(16,770)	(8,239)
Deferred income taxes	(876)	(906)	(4,058)
Current income taxes	(9,525)	(15,864)	(4,181)
Effective tax rate of income taxes	29.4%	31.3%	(29.2)%
(1) It relates to Brazilian income taxes on earnings of offshore investees, as established by Law No. 12,973/2014.
(2) It includes provisions for legal proceedings and payment of an administrative contribution over the TFC Pre-70 for the administrative funding of the PPSP-R pre-70 and PPSP-NE pre-70 plans.

 

 

Deferred income taxes - non-current

The changes in the deferred income taxes are presented as follows:

	2023	2022
Opening balance	(5,918)	(625)
Recognized in the statement of income for the period	(876)	(906)
Recognized in shareholders’ equity	(2,559)	(3,220)
Translation adjustment	(602)	(45)
Use of tax loss carryforwards	−	(1,123)
Others	10	1
Closing balance	(9,945)	(5,918)

 

 

The composition of deferred tax assets and liabilities is set out in the following table:

Nature	Realization basis	12.31.2023	12.31.2022
PP&E - Exploration and decommissioning costs	Depreciation, amortization and write-offs of assets	(6,296)	(6,587)
PP&E - Impairment	Amortization, impairment reversals and write-offs of assets	4,203	3,602
PP&E - Right-of-use assets	Depreciation, amortization and write-offs of assets	(9,369)	(5,611)
PP&E - depreciation methods and capitalized borrowing costs	Depreciation, amortization and write-offs of assets	(18,784)	(15,438)
Loans, trade and other receivables / payables and financing	Payments, receipts and considerations	(2,479)	810
Leasings	Appropriation of the considerations	9,240	6,045
Provision for decommissioning costs	Payments and use of provisions	8,010	6,745
Provision for legal proceedings	Payments and use of provisions	954	885
Tax loss carryforwards	Taxable income compensation	1,140	914
Inventories	Sales, write-downs and losses	411	333
Employee Benefits	Payments and use of provisions	2,036	1,518
Others		989	866
Total		(9,945)	(5,918)
Deferred tax assets		965	832
Deferred tax liabilities		(10,910)	(6,750)

 

 

Timing of reversal of deferred income taxes

Deferred tax assets were recognized based on projections of taxable profit in future periods supported by the assumptions within the Company’s Strategic Plan 2024-2028, whose pillars are the preservation of financial strength, financial and environment resilience of projects, and focus on value creation.

Management considers that the deferred tax assets will be realized to the extent the deferred tax liabilities are reversed and expected taxable events occur based on its Strategic Plan 2024-2028.

The estimated schedule of recovery/reversal of net deferred tax assets (liabilities) as of December 31, 2023 is set out in the following table:

	Assets	Liabilities
2024	138	(1,646)
2025	58	2,540
2026	61	402
2027	73	744
2028	71	(255)
2029  and thereafter	564	9,125
Recognized deferred tax assets	965	10,910

 

 

In addition, the Company has tax loss carryforwards arising from offshore subsidiaries, for which no deferred taxes were recognized.

		Assets
	12.31.2023	12.31.2022
Brazil	368	-
Abroad	780	987
Unrecognized deferred tax assets	1,148	987

 

 

These unrecognized deferred tax assets arise mainly from subsidiaries operating in the oil and gas exploration and production and refining activities in the United States. In 2023, the Company recognized US$ 26 of previously unrecognized deferred tax assets due to a reassessment of their recoverability related to expected future taxable income arising from business operations.

An aging of the unrecognized deferred tax assets from companies abroad is set out below:

	2030 - 2032	2033 - 2035	2036 -2038	Undefined expiration	Total
Unrecognized deferred tax assets	285	299	141	55	780

 

 

Uncertain tax treatments on income taxes

As of December 31, 2023, the Company had US$ 6,982 (US$ 6,043 as of December 31, 2022) of uncertain tax treatments on income taxes, related to judicial and administrative proceedings (see note 19.3). Additionally, as of December 31, 2023, the Company has other positions that can be considered as uncertain tax treatments on income taxes amounting to US$ 4,063 (US$ 30,020 as of December 31, 2022), given the possibility of different interpretation by the tax authority. These uncertain tax treatments are supported by technical assessments and tax risk assessment methodology. Therefore, Petrobras believes that such positions are likely to be accepted by the tax authorities (including judicial courts).

Uncertain treatments on Corporate Income Tax (CIT)

In 2023, the Company received additional charges from the Dutch tax authority, due to a final assessment on the calculation of the Corporate Income Tax (CIT) of subsidiaries in the Netherlands from 2018 to 2020, arising from the valuation for tax purposes of platforms and equipment nationalized under the Repetro tax regime, in the amount of US$ 595, updated by applicable interest rate.

Tax treatments of certain subsidiaries from 2020 to 2022 have not yet been assessed by this tax authority. Any charges by the Dutch tax authority for those years, on a similar basis to the periods already assessed, could reach the amount of US$ 242. Thus, as of December 31, 2023, the total amount of these uncertain tax treatments is US$ 837, updated by applicable interest rate.

The Company continues to defend its position but understands that it is not probable that the tax authority will fully accept this tax treatment. Thus, a liability was recognized with a corresponding effect in income taxes within the statement of income for the period, by means of the expected value method, constituted by the sum of amounts weighted by the probability of loss.

Accounting policy for income taxes

The Company calculates income taxes in accordance with current legislation and applying the rates in effect at the end of reporting period. Income taxes expense for the period are recognized in the statement of income of the period, except when the tax arises from a transaction or event which is recognized directly in equity.

a)

Current income taxes

Current income taxes are offset when they relate to income taxes levied on the same taxable entity and by the same tax authority, when there is a legal right and the entity has the intention to set off current tax assets and current tax liabilities, simultaneously.

Uncertain tax treatments are periodically assessed, considering the probability of acceptance by the tax authority.

b)

Deferred income taxes

Deferred income taxes are generally recognized on temporary differences between the tax base of an asset or liability and its carrying amount. They are measured at the tax rates that are provided for in the specific legislation to apply to the period when the asset is realized or the liability is settled.

Deferred tax assets and liabilities are recognized for all deductible temporary differences and carryforward of unused tax losses or credits to the extent that it is probable that taxable profit will be available against which those deductible temporary differences can be utilized. When there are insufficient taxable temporary differences relating to the same taxation authority and the same taxable entity, a deferred tax is recognized to the extent that it is probable that the entity will have sufficient taxable profit in future periods, based on projections approved by management and supported by the Company’s Strategic Plan.

Deferred tax assets and liabilities are offset when they relate to income taxes levied on the same taxable entity, when a legally enforceable right to set off current tax assets and current tax liabilities exists and when the deferred tax assets and deferred tax liabilities relate to taxes levied by the same tax authority on the same taxable entity.

17.2.

Other taxes

	Current assets		Non-current assets		Current liabilities		Non-current liabilities (1)
	12.31.2023	12.31.2022	12.31.2023	12.31.2022	12.31.2023	12.31.2022	12.31.2023	12.31.2022
Taxes in Brazil
Current / Non-current ICMS (VAT)	592	716	607	473	1,032	699	−	−
Current / Non-current PIS and COFINS	304	378	2,876	2,362	265	28	141	89
Claim to recover PIS and COFINS	−	−	733	657	−	−	−	−
CIDE	−	1	−	−	−	5	−	−
Production taxes	−	−	−	−	2,094	1,996	145	114
Withholding income taxes	−	−	−	−	272	149	−	−
Others	58	40	290	273	443	152	90	90
Total in Brazil	954	1,135	4,506	3,765	4,106	3,029	376	293
Taxes abroad	6	7	10	13	60	19	−	−
Total	960	1,142	4,516	3,778	4,166	3,048	376	293
(1) Other non-current taxes are classified within other non-current liabilities in the statement of financial position.

 

Current and non-current ICMS (VAT) credits arise from requests for extemporaneous and overpaid tax, offset in accordance with the legislation of each state. They also arise on the acquisition of assets for property, plant and equipment, which are offset in a straight line over 4 years.

Current and non-current PIS/COFINS credits mainly refer to the acquisition of goods and services for assets under construction, since their use is permitted only after these assets enter into production, as well as to extemporaneous tax credits.

Production taxes are financial compensation due to the Brazilian Federal Government by companies that explore and produce oil and natural gas in Brazilian territory. They are composed of royalties, special participations, signature bonuses and payment for retention or occupation of area. They include the amounts referring to an agreement with the ANP to close a legal proceeding involving the recalculation of royalties and special participations relating to oil production in the Jubarte field, from August 2009 to February 2011 and from December 2012 to February 2015.

 

From March 1 to June 30, 2023, Export Tax was charged on the exports of crude oil, for which the Company recognized US$ 285 as other taxes within the statement of income.

Claim to recover PIS and COFINS

The Company filed four civil lawsuits against the Brazilian Federal Government, claiming to recover PIS and COFINS paid over finance income and foreign exchange variation gains, from February 1999 to January 2004.

The court granted to the Company, in all the lawsuits, the definitive right to recover those taxes. Regarding two actions relating to Petroquisa, a former subsidiary that had been incorporated by the Company, the corresponding amounts were paid by the Brazilian Federal Government in 2023. In relation to the two remaining cases, both had rulings by the court favorable to the Company and, in one of them, the Brazilian Federal Government has already expressed its agreement and there was a decision in favor of the Company, still subject to appeal. Regarding the other lawsuit, there is no court decision at this point.

Pillar Two - Global Minimum Top-up Tax

In December 2021, the Organization for Economic Cooperation and Development (OECD) released the Pillar Two model rules to reform international corporate taxation that aim to ensure that multinationals with revenues exceeding €750 million pay a minimum top up tax on profits of its subsidiaries that are taxed at an effective tax rate of less than 15% per jurisdiction (Global Minimum Top-up Tax).

If the Parent Entity is located in a jurisdiction that has not implemented the top-up tax, this tax will be levied on the next entity in the organizational structure located in a jurisdiction that has implemented it, following a top-down approach. On December 19, 2023, the Netherlands enacted the Pillar Two income taxes legislation effective on January 1, 2024.

Petrobras is in the process of assessing if there is any exposure arising from Pillar Two legislation. Based on a preliminary assessment of the new rules, Petrobras does not expect a material exposure. Considering that the information for a comprehensive analysis is still being evaluated and due to the complexity of the new legislation, Petrobras expects to complete the assessment during 2024.

Petrobras applied the temporary exemption described in the amendments to IAS 12, issued by the IASB in May 2023, on the accounting for income taxes. Accordingly, the Company neither recognizes nor discloses information about deferred tax assets or liabilities related to the Pillar Two.

18.	Employee benefits

Employee benefits are all forms of consideration given by an entity in exchange for service rendered by employees or for the termination of employment. It also includes expenses with directors and management. Such benefits include salaries, post-employment benefits, termination benefits and other benefits.

	12.31.2023	12.31.2022
Liabilities
Short-term employee benefits	1,986	1,452
Termination benefits	143	192
Post-employment benefits	16,382	11,246
Total	18,511	12,890
Current	2,932	2,215
Non-current	15,579	10,675

 

 

18.1.

Short-term employee benefits

	12.31.2023	12.31.2022
Variable compensation programs	464	489
Accrued vacation	574	505
Salaries and related charges and other provisions	343	327
Profit sharing	605	131
Total	1,986	1,452
Current	1,944	1,421
Non-current (1)	42	31
(1) Remaining balance relating to the four-year deferral of 40% of the PPP portion of executive officers and the upper management.

 

 

The Company recognized the following amounts in the statement of income:

Expenses recognized in the statement of income	2023	2022	2021
Salaries, accrued vacations and related charges	(3,478)	(3,006)	(2,665)
Variable compensation programs (1)	(416)	(547)	(469)
Profit sharing (1)	(595)	(131)	(125)
Management fees and charges	(14)	(14)	(15)
Total	(4,503)	(3,698)	(3,274)
(1) It includes adjustments to provisions related to previous years.

 

 

18.1.1.

Variable compensation programs

Performance award programs (Programa de Prêmio por Desempenho - PPP and Programa de Prêmio por Performance - PRD)

In 2023, the Company paid US$ 562 in relation to the PPP for 2022, since the metrics relating to the Company’s and individual performances were achieved in 2022.

For 2023, Petrobras revised its variable compensation program, implementing the PRD in replacement of the PPP. In the new model, the PRD is aimed at employees with and without managerial function, as a complementary program to the Profit Sharing (PLR).

The PRD intends to recognize the effort and individual performance of each employee to achieve the Company’s results. The amounts to be paid to each employee continues to be defined by the achievement of the key metrics (which currently are Delta Valor Petrobras - VALOR, Greenhouse Gas Emissions Target Achievement Indicator - IAGEE, and Oil Leak Volume Indicator - VAZO) and of the individual goals (performance management score for all employees, with exception of executive managers, for whom the scorecard of their respective departments will be considered).

The PRD establishes that, in order to trigger this payment, it is necessary to have a declaration and payment of distribution to shareholders approved by the Company’s Board of Directors, as well as net income for the year.

The total amount is limited to a percentage of the net income or the Adjusted EBITDA for the year (a non-GAAP measure defined as net income plus net finance income (expense); income taxes; depreciation, depletion and amortization; results in equity-accounted investments; impairment of assets; results on disposal/write-offs of assets; and results from co-participation agreements in bid areas). For 2023, the PRD is limited to 5% of the adjusted EBITDA.

In 2023, the Company provisioned US$ 415 relating to the PRD (US$ 553 for 2022), recorded in other income and expenses, including variable compensation programs from consolidated companies.

Profit Sharing (Participações nos lucros ou resultados - PLR)

In 2023, the Company settled US$ 134 related to the PLR 2022, considering the agreement for the PLR 2021 and 2022, approved by the Secretariat of Management and Governance of State-owned Companies (SEST), which provided that only employees without managerial functions would be entitled to receive profit sharing with individual limits according to their remuneration.

For 2023, considering the change implemented in the Company's variable compensation programs, the PLR will also include employees with managerial functions, and it becomes the main variable compensation program of the Company.

For the payment of PLR relating to 2023, the Company needs to meet the following triggers: declaration and payment of distribution to shareholders approved by the Company’s Board of Directors, net income for the year, as well as achieving at least 80% of the weighted average of a set of proposed indicators.

For 2023, the total amount is limited to the lower of 6.25% of the net income and to 25% of the distribution to shareholders.

In 2023, the Company provisioned US$ 591 referring to PLR for 2023 (US$ 132 for 2022), recorded in other income and expenses.

Accounting policy for variable compensation programs (PRD, PPP and PLR)

The provisions for variable compensation programs are recognized on an accrual basis, during the periods in which the employees provided services. They represent the estimates of future disbursements arising from past events, based on the criteria and metrics of the PRD, PPP and PLR, provided that the requirements for activating these programs are met and that the obligation can be reliably estimated.

18.2.

Termination benefits

Termination benefits are employee benefits provided in exchange for the termination of labor contract as a result of either: i) the Company’s decision to terminate the labor contract before the employee’s normal retirement date; or ii) an employee’s decision to accept an offer of benefits in exchange for the termination of their employment.

Voluntary severance programs

The Company has voluntary severance programs specific for employees of the corporate segment and of divested assets, which provide for the same legal and indemnity advantages.

In 2023, 481 employees retired through these programs, while there were 55 enrollments and 179 withdrawals. Changes to the provisions for termination benefits are presented as follows:

	2023	2022
Opening Balance	192	349
Effects in the statement of income	(10)	16
Enrollments	6	18
Revision of provisions	(16)	(2)
Effects in cash and cash equivalents	(53)	(199)
Settlements in the period	(53)	(199)
Translation adjustment	14	26
Closing Balance	143	192
Current	81	75
Non-current	62	117

 

 

The provision for expenses is recognized as employees enroll to the programs.

The Company disburse the severance payments in two installments, one at the time of termination and the remainder one year after the termination.

As of December 31, 2023, from the balance of US$ 143, US$ 26 refers to the second installment of 494 retired employees and US$ 117 refers to 1,046 employees enrolled in voluntary severance programs with expected termination by September 2025.

18.3.

Post-employment benefits

The Company maintains a health care plan for its employees in Brazil (active and retiree) and their dependents (Saúde Petrobras - AMS), and five other major plans of post-employment benefits (collectively referred to as “pension plans”).

The following table presents the balance of post-employment benefits:

	12.31.2023	12.31.2022
Liabilities
Health Care Plan - Saúde Petrobras - AMS	9,662	5,813
Petros Pension Plan - Renegotiated (PPSP-R)	4,221	3,606
Petros Pension Plan - Non-renegotiated (PPSP-NR)	1,338	1,041
Petros Pension Plan - Renegotiated - Pre-70 (PPSP-R Pre 70)	519	284
Petros Pension Plan - Non-renegotiated - Pre-70 (PPSP-NR Pre 70)	461	339
Petros 2 Pension Plan (PP-2)	181	163
Total	16,382	11,246
Current	907	719
Non-current	15,475	10,527

 

18.3.1.

Nature and risks associated with defined benefit plans

Health Care Plan

The health care plan Saúde Petrobras – AMS is managed and run by Petrobras Health Association (Associação Petrobras de Saúde – APS), a nonprofit civil association, and includes prevention and health care programs. The plan offers assistance to all employees, retirees, pensioners and eligible family members, according to the rules of the plan, and is open to new employees.

Currently sponsored by Petrobras, Transpetro, PBIO, TBG and Termobahia, this plan is primarily exposed to the risk of increase in medical costs due to inflation, new technologies, new types of coverage and an increase in the utilization of medical benefits. The Company continuously improves the quality of its technical and administrative processes, as well as the health programs offered to beneficiaries in order to mitigate such risks.

Employees, retirees and pensioners make monthly fixed contributions to cover high-risk procedures and variable contributions for the cost of medical procedures, both based on the contribution tables of the plan, which are determined based on certain parameters, such as salary and age levels. The plan also includes assistance towards the purchase of certain medicines through reimbursement or acquisition and home delivery, with co-participation of beneficiaries.

Benefits are paid by the Company based on the costs incurred by the beneficiaries. The financial participation of the Company and the beneficiaries on the expenses are provided for in the Collective Bargaining Agreement (ACT), being 60% by the Company and 40% by the participants.

As provided in clause 37, paragraph 2 of the Collective Bargaining Agreement 2023-2025, if the resolutions No. 42/2022 and No. 49/2023 of the Commission on Corporate Governance and the Administration of Corporate Holdings of the Brazilian Federal Government (Comissão de Governança Corporativa e de Administração de Participações Societárias da União – CGPAR) are revoked or amended, allowing adjustments in the cost-sharing of health care plans, the Company and the labor unions will meet to implement a new cost-sharing arrangement, in order to minimize the impact on the income of its beneficiaries.

Annual revision of the health care plan

At December 31, 2023, this obligation was revised using the revised actuarial assumptions, which results are shown in note 18.3.2.

Pension plans

The Company’s post-retirement plans are managed by Petros Foundation (Fundação Petrobras de Seguridade Social), a nonprofit legal entity governed by private law with administrative and financial autonomy.

Pension plans in Brazil are regulated by the National Council for Supplementary Pension (Conselho Nacional de Previdência Complementar – CNPC), which establishes all guidelines and procedures to be adopted by the plans for their management and relationship with stakeholders.

Petros Foundation periodically carries out revisions of the plans and, when applicable, establishes measures aiming at maintaining the financial sustainability of the plans.

The net obligation with pension plans recorded by the Company is measured in accordance with the requirements of IFRS which has a different measurement methodology to that applicable to pension funds, regulated by the Post-Retirement Benefit Federal Council (Conselho Nacional de Previdência Complementar – CNPC).

On March 29, 2023, the Deliberative Council of Petros Foundation approved the financial statements of the pension plans for the year ended December 31, 2022, sponsored by the Company.

The following table below presents the reconciliation of the deficit of Petros Plan registered by Petros Foundation as of December 31, 2022 with the net actuarial liability registered by the Company at the same date (an updated reconciliation with the results of the plans as of December 31, 2023 will be disclosed in the first quarter of 2024, after the approval of Petros Foundation Deliberative Council of its financial statements for the year):

	PPSP-R (1)	PPSP-NR (1)
Deficit registered by Petros	330	341
Ordinary and extraordinary future contributions - sponsor	4,212	1,079
Contributions related to the TFC - sponsor	691	391
Financial assumptions (interest rate and inflation), changes in fair value of plan assets and actuarial valuation method	(1,343)	(431)
Net actuarial liability recorded by the Company	3,890	1,380
(1) It includes the balance of PPSP-R pre-70 and PPSP-NR pre-70.

 

 

·

Sponsor Contributions – in the calculation of the obligation, Petros considers the future cash flow of ordinary and extraordinary sponsor and participants contributions, discounted to present value, according to the CNPC criteria, while the Company only considers them as they are made.

·

Financial Assumptions - the main difference is the definition of the real interest rate established by Petros, which is according to the expected profitability of the current investment portfolios and the parameters published by the CNPC, considering a moving average of recent years in setting safety limits. On the other hand, the Company determines the real interest rates through an equivalent rate that combines the maturity profile of pension and healthcare obligations with the future yield curve of long-term Brazilian Federal Government securities (“Tesouro IPCA”, formerly known as NTN).