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Subsequent events

12 Months Ended

Dec. 31, 2022

37.

Subsequent events

Leniency Agreement

On January 16, 2023, Petrobras received the amount of US$ 87 (R$ 456 million), recovered through a leniency agreement of the company UOP LLC – a subsidiary of Honeywell International Inc. – entered into with General Federal Inspector’s Office (CGU - Controladoria Geral da União) and the Federal Attorney General's Office (AGU – Advocacia Geral da União).

Receipt of the earn out relating to Atapu and Sépia fields

In January 2023, Petrobras received the entire amount of US$ 384 (R$ 2,007 million), of the earn out related to 2022, from the partners in Atapu and Sépia fields, including gross up of taxes, as follows:

US$ 258 (R$1,347 million) relating to the interest held by TotalEnergies (28%), Petronas Petróleo Brasil Ltda (21%) and QatarEnergy Brasil Ltda (21%), in the Sépia field;

US$ 126 (R$ 660 million) relating to the interest held by TotalEnergies (22.5%) and the interest of Shell (25%), in the Atapu field.

For more information, see note 24.

Sale of the Albacora Leste field

On January 26, 2023, after fulfilling all the conditions precedent, Petrobras concluded the sale of its entire interest in Albacora Leste producing field, located in the Campos Basin, to the company Petro Rio Jaguar Petróleo LTDA (PetroRio), a subsidiary of Petro Rio S.A.

The transaction was closed with the receipt, in cash, of US$ 1,635, including price adjustments provided for in the contract.

With this closing, PetroRio becomes the operator of this field, with a 90% interest, in partnership with Repsol Sinopec Brasil, which holds the remaining 10%.

For more information, see note 30.

Receipt of the earn out relating to Baúna field

On January 30, 2023, Petrobras received US$ 84, including price adjustments provided for in the contract, from Karoon Petróleo & Gás Ltda (Karoon), a subsidiary of Karoon Energy Ltd, as a contingent payment related to Brent prices of 2022.

This receipt is in accordance with the terms of the agreement signed by the companies in 2020, relating to the sale of Petrobras' entire interest in Baúna field (concession area BM-S-40). The other contingent payments may be received by Petrobras until 2026, depending on Brent prices in future years.

Results on judgments of the Administrative Board of Tax Appeals (Conselho Administrativo de Recursos Fiscais - CARF)

On February 1, 2023, the First Panel of the Superior Chamber of Tax Appeals (CSRF), a member of the CARF, dismissed the appeals filed by the Company and decided that Petrobras owed income taxes (IRPJ and CSLL) on subsidiary abroad relating to 2011 and 2012. This decision was taken by exercising the casting vote of the President of the Class, based on Provisional Measure no. 1160/2023, after a tie between the judges. With this decision, tax debts amounting to US$ 1,092 (R$ 5,700) became final at administrative level. Accordingly, after the end of the administrative process, the Company will adopt the appropriate measures.

ii.

On March 14, 2023, the Third Panel of the CSRF, by majority, dismissed the special appeals filed by the Company, understanding that CIDE and PIS/COFINS over Imports, related to vessel charter payments to legal entities abroad in 2010 (PIS/COFINS), 2011 (CIDE) and 2013 (CIDE, PIS/COFINS). With this decision, tax debts of US$ 3.5 billion (R$ 18 billion) became final at administrative level. Accordingly, after the end of the administrative process, the Company will adopt the appropriate measures.

The expectation of loss in these contingencies is deemed possible (see note 18). These decisions do not trigger any provisioning in the Company's financial statements.

Supplementary information on Oil and Gas Exploration and Production (unaudited)

In accordance with Codification Topic 932 - Extractive Activities – Oil and Gas, this section provides supplemental information on oil and gas exploration and production activities of the Company. The information included in items (i) through (iii) provides historical cost information pertaining to costs incurred in exploration, property acquisition and development, capitalized costs and results of operations. The information included in items (iv) and (v) presents information on Petrobras’ estimated net proved reserve quantities, standardized measure of estimated discounted future net cash flows related to proven reserves, and changes in estimated discounted future net cash flows.

The Company, on December 31, 2022, maintains activities mainly in Brazil, in addition to activities in Argentina, Colombia and Bolivia, in South America. The equity-accounted investments are comprised of the operations of the joint venture company MP Gulf of Mexico, LLC (MPGoM), in which Murphy Exploration & Production Company ("Murphy" ) has 80% stake and Petrobras America Inc ("PAI") 20% stake in United States of America, North America. The Company reports its reserves in Brazil, United States of America and Argentina. Bolivian reserves are not included due to restrictions determined by Bolivian Constitution. In Colombia, our activities are exploratory, and therefore, there are no associated reserves.

i) Capitalized costs relating to oil and gas producing activities

As set out in note 26, the Company uses the successful efforts method of accounting for appraisal and development costs of crude oil and natural gas production. In addition, notes 23 and 24 presents the accounting policies applied by the Company for recognition, measurement and disclosure of property, plant and equipment and intangible assets.

The following table summarizes capitalized costs for oil and gas exploration and production activities with the related accumulated depreciation, depletion and amortization, and asset retirement obligations:

Schedule of capitalized costs for oil and gas exploration and production activities
	Consolidated entities
		Abroad				Equity Method Investees
	Brazil	South America	Others	Total	Total	Equity Method Investees
December 31, 2022
Unproved oil and gas properties	4,227	55	−	55	4,282	−
Proved oil and gas properties	83,030	205	−	205	83,235	762
Support Equipment	69,735	732	1	733	70,468	−
Gross Capitalized costs	156,993	992	1	993	157,986	762
Depreciation, depletion and amortization	(52,836)	(769)	(1)	(770)	(53,606)	(224)
Net capitalized costs	104,156	223	−	223	104,380	538
December 31, 2021
Unproved oil and gas properties	4,455	115	-	115	4,570	-
Proved oil and gas properties	80,523	172	-	172	80,695	832
Support Equipment	67,988	777	1	778	68,766	-
Gross Capitalized costs	152,967	1,064	1	1,065	154,032	832
Depreciation, depletion and amortization	(51,621)	(733)	(1)	(734)	(52,355)	(296)
Net capitalized costs	101,345	331	-	331	101,677	536
December 31, 2020
Unproved oil and gas properties	17,438	112	-	112	17,550	-
Proved oil and gas properties	61,857	140	-	140	61,997	792
Support Equipment	73,199	761	1	762	73,961	-
Gross Capitalized costs	152,494	1,013	1	1,014	153,508	792
Depreciation, depletion and amortization	(43,008)	(687)	(1)	(688)	(43,696)	(316)
Net capitalized costs	109,486	326	-	326	109,812	476

ii) Costs incurred in oil and gas property acquisition, exploration and development activities

Costs incurred are summarized below and include both amounts expensed and capitalized:

	Consolidated entities
		Abroad			Equity Method Investees
	Brazil	South America	Total	Total	Equity Method Investees
December 31, 2022
Acquisition costs:
Proved	−	−	−	−	−
Unproved	892	−	−	892	−
Exploration costs	707	51	51	758	1
Development costs	6,883	31	31	6,914	30
Total	8,482	82	82	8,564	31
December 31, 2021
Acquisition costs:
Proved	−	−	−	−	−
Unproved	−	−	−	−	−
Exploration costs	682	5	5	687	−
Development costs	6,035	44	44	6,079	37
Total	6,717	49	49	6,766	37
December 31, 2020
Acquisition costs:
Proved	315	−	−	315	−
Unproved	24	−	−	24	−
Exploration costs	805	10	10	815	−
Development costs	5,664	3	3	5,667	57
Total	6,808	13	13	6,821	57

(iii) Results of operations for oil and gas producing activities

The Company’s results of operations from oil and gas producing activities for the years ended December 31, 2022, 2021 and 2020 are shown in the following table. The Company transfers substantially all of its Brazilian crude oil and gas production to the Refining, Transportation & Marketing segment in Brazil. The internal transfer prices calculated by the Company’s model may not be indicative of the price the Company would have realized had this production been sold in an unregulated spot market. Additionally, the prices calculated by the Company’s model may not be indicative of the future prices to be realized by the Company. Gas prices used are those set out in contracts with third parties.

Production costs are lifting costs incurred to operate and maintain productive wells and related equipment and facilities, including operating employees’ compensation, materials, supplies, fuel consumed in operations and operating costs related to natural gas processing plants.

Exploration expenses include the costs of geological and geophysical activities and projects without economic feasibility. Depreciation and amortization expenses relate to assets employed in exploration and development activities. In accordance with Codification Topic 932 – Extractive Activities – Oil and Gas, income taxes are based on statutory tax rates, reflecting allowable deductions. Interest income and expense are excluded from the results reported in this table.

Schedule of Oil and Gas, income taxes are based on statutory tax rates, reflecting allowable deductions
	Consolidated entities
		Abroad					Equity Method Investees
	Brazil	South America	North America	Others	Total	Total	Equity Method Investees
December 31, 2022
Net operation revenues:
Sales to third parties	1,153	158	−	−	158	1,311	275
Intersegment	76,579	−	−	−	−	76,579	−
	77,732	158	−	−	158	77,890	275
Production costs	(19,975)	(75)	−	−	(75)	(20,050)	(41)
Exploration expenses	(719)	(168)	−	−	(168)	(887)	−
Depreciation, depletion and amortization	(10,373)	(42)	−	−	(42)	(10,415)	(42)
Impairment of oil and gas properties	(1,216)	(2)	−	−	(2)	(1,218)	−
Other operating expenses	3,000	(1)	(8)	21	12	3,012	(22)
Results before income tax expenses	48,449	(130)	(8)	21	(117)	48,332	170
Income tax expenses	(16,474)	44	−	(3)	41	(16,433)	−
Results of operations (excluding corporate overhead and interest costs)	31,975	(86)	(8)	19	(76)	31,899	170
December 31, 2021
Net operation revenues:
Sales to third parties	974	131	−	−	131	1,105	220
Intersegment	54,479	−	−	−	−	54,479	−
	55,453	131	−	−	131	55,584	220
Production costs	(14,601)	(67)	−	−	(67)	(14,668)	(44)
Exploration expenses	(685)	(2)	−	−	(2)	(687)	−
Depreciation, depletion and amortization	(8,959)	(46)	−	−	(46)	(9,005)	(38)
Impairment of oil and gas properties	3,107	−	−	−	−	3,107	−
Other operating expenses	809	15	114	(118)	11	820	(17)
Results before income tax expenses	35,124	31	114	(118)	27	35,151	121
Income tax expenses	(11,984)	(11)	−	43	33	(11,951)	−
Results of operations (excluding corporate overhead and interest costs)	23,141	20	114	(75)	59	23,200	121
December 31, 2020
Net operation revenues:
Sales to third parties	763	108	−	−	108	871	148
Intersegment	33,524	−	−	−	−	33,524	−
	34,287	108	−	−	108	34,395	148
Production costs	(9,378)	(59)	−	−	(59)	(9,437)	(54)
Exploration expenses	(796)	(7)	−	−	(7)	(803)	−
Depreciation, depletion and amortization	(8,611)	(50)	−	−	(50)	(8,661)	(57)
Impairment of oil and gas properties	(7,364)	−	−	−	−	(7,364)	−
Other operating expenses	(825)	(2)	(167)	(26)	(195)	(1,020)	(158)
Results before income tax expenses	7,313	(10)	(167)	(26)	(203)	7,110	(121)
Income tax expenses	(2,486)	3	57	9	69	(2,417)	41
Results of operations (excluding corporate overhead and interest costs)	4,827	(7)	(110)	(17)	(134)	4,693	(80)

(iv) Reserve quantities information

As presented in note 4.1, proved oil and 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 producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. The project to extract the hydrocarbons must have commenced or there must be reasonable certainty that the project will commence within a reasonable time. Reserves estimate involves a high degree of judgment and complexity and its application affects different items of these Financial Statements.

The Company’s estimated net proved oil and gas reserves and changes thereto for the years 2022, 2021 and 2020 are presented in the following table. Proved reserves are estimated in accordance with the reserve definitions prescribed by the Securities and Exchange Commission.

Proved developed oil and gas reserves are proved reserves that can be expected to be recovered: (i) through existing wells with existing 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 installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is done by means not involving a well.

Proved reserves for which substantial new investments in additional wells and related facilities will be required are named proved undeveloped reserves.

Reserve estimates are subject to variations due to technical uncertainties in the reservoir and changes in economic scenarios. A summary of the annual changes in the proved reserves of oil is as follows (in millions of barrels):

Summary of the annual changes in the proved reserves of oil is as follows (in millions of barrels):
	Consolidated Entities				Equity Method Investees
*Proved developed and undeveloped reserves()**	Crude oil in Brazil	Crude Oil in South America	Synthetic Oil in Brazil	Consolidated Total	Crude Oil in North America	Crude Oil in Africa	Total
Reserves at December 31, 2019	8,083	1	8	8,092	23	42	8,156
Revisions of previous estimates	269	(1)	(7)	261	−	−	261
Extensions and discoveries	35	−	−	35	−	−	35
Improved Recovery	−	−	−	−	−	−	−
Sales of reserves	(61)	−	−	(61)	−	(41)	(102)
Purchases of reserves	−	−	−	−	−	−	−
Production for the year	(792)	−	(1)	(793)	(4)	(1)	(798)
Reserves at December 31, 2020	7,534	−	−	7,534	18	−	7,552
Extensions and discoveries	−	−	−	−	−	−	−
Revisions of previous estimates	1,654	2	11	1,667	1	−	1,668
Sales of reserves	(9)	−	−	(9)	−	−	(9)
Production for the year	(773)	−	(1)	(774)	(3)	−	(777)
Reserves at December 31, 2021	8,406	2	10	8,419	17	−	8,435
Revisions of previous estimates	1,705	−	−	1,705	3	−	1,708
Sales of reserves (1)	(455)	−	(10)	(465)	(1)	−	(465)
Production for the year	(748)	−	(1)	(749)	(3)	−	(752)
Reserves at December 31, 2022	8,908	2	−	8,910	16	−	8,926

(1) Includes the effects of the write-offs related to the Co-Participation Agreements of Atapu and Sepia fields

(*) Apparent differences in the sum of the numbers are due to rounding off.

A summary of the annual changes in the proved reserves of natural gas is as follows (in billions of cubic feet):

Summary of of the annual changes in the proved reserves of natural gas is as follows (in billions of cubic feet):
	Consolidated Entities				Equity Method Investees
*Proved developed and undeveloped reserves ()**	Natural Gas in Brazil	Natural Gas in South America	Synthetic Gas in Brazil	Consolidated Total	Gas Natural in North America	Gas Natural in Africa	Total
Reserves at December 31, 2019	8,381	156	12	8,549	9	47	8,605
Revisions of previous estimates	(93)	(119)	(11)	(222)	−	−	(222)
Extensions and discoveries	36	−	−	36	−	−	36
Improved Recovery	−	−	−	−	−	−	−
Sales of reserves	(42)	−	−	(42)	−	(47)	(90)
Purchases of reserves	−	−	−	−	−	−	−
Production for the year	(735)	(12)	(1)	(749)	(2)	−	(750)
Reserves at December 31, 2020	7,547	26	−	7,572	8	−	7,580
Extensions and discoveries	−	−	−	−	−	−	−
Revisions of previous estimates	1,615	167	19	1,802	−	−	1,802
Sales of reserves	(15)	−	−	(15)	−	−	(15)
Production for the year	(692)	(16)	(1)	(709)	(1)	−	(710)
Reserves at December 31, 2021	8,455	177	18	8,650	7	−	8,657
Revisions of previous estimates	1,667	16	−	1,682	−	−	1,682
Sales of reserves (1)	(408)	−	(17)	(425)	(1)	−	(425)
Production for the year	(626)	(20)	(1)	(647)	(1)	−	(648)
Reserves at December 31, 2022	9,088	173	−	9,261	6	−	9,267

(1) Includes the effects of the write-offs related to the Co-Participation Agreements of Atapu and Sepia fields

(*) Apparent differences in the sum of the numbers are due to rounding off.

Natural gas production volumes used in these tables are the net volumes withdrawn from our proved reserves, including gas consumed in operations and excluding reinjected gas. Our disclosure of proved gas reserves includes gas consumed in operations, which represent 37% of our total proved reserves of natural gas as of December 31, 2022.

The tables below summarize information about the changes in total proved reserves of crude oil and natural gas, in millions of barrels of oil equivalent, in our consolidated entities and equity method investees for 2022, 2021 and 2020:


	Consolidated Entities				Equity Method Investees
*Proved developed and undeveloped reserves()**	Oil equivalent in Brazil	Oil equivalent in South America	Synthetic Oil in Brazil	Consolidated Total	Oil equivalent in North America	Oil equivalent in Africa	Total
Reserves at December 31, 2019	9,480	27	10	9,517	24	49	9,590
Revisions of previous estimates	253	(21)	(9)	224	−	−	224
Extensions and discoveries	41	−	−	41	−	−	41
Improved Recovery	−	−	−	−	−	−	−
Sales of reserves	(68)	−	−	(68)	−	(49)	(117)
Purchases of reserves	−	−	−	−	−	−	−
Production for the year	(914)	(2)	(1)	(918)	(5)	(1)	(923)
Reserves at December 31, 2020	8,792	5	−	8,796	19	−	8,816
Extensions and discoveries	−	−	−	−	1	−	1
Revisions of previous estimates	1,923	30	14	1,967	2	−	1,969
Sales of reserves	(11)	−	−	(11)	−	−	(11)
Production for the year	(888)	(3)	(1)	(892)	(3)	−	(896)
Reserves at December 31, 2021	9,816	31	13	9,860	18	−	9,878
Revisions of previous estimates	1,983	3	−	1,986	3	−	1,988
Sales of reserves (1)	(523)	−	(12)	(536)	(1)	−	(536)
Production for the year	(852)	(4)	(1)	(857)	(3)	−	(860)
Reserves at December 31, 2022	10,423	31	−	10,453	17	−	10,470

(1) Includes the effects of the write-offs related to the Co-Participation Agreements of Atapu and Sepia fields

(*) Apparent differences in the sum of the numbers are due to rounding off.

In 2022, we incorporated 1,988 million boe of proved reserves by revising previous estimates, including:

(i) addition of 1,279 million boe due to new projects, mainly in Búzios field and in other fields in the Santos and Campos Basins; and

(ii) addition of 709 million boe arising from other revisions, mainly due to good performance of reservoirs in the pre-salt layer of Santos Basin and to the contract term extension of Rio Urucu and Leste do Urucu fields.

We did not have relevant changes related to the variation in the oil price.

The addition in our proved reserves were partially offset by the reduction of 536 million boe, due to the effects of the transfer of interests of 5% of the Surplus Volume of the Transfer of Rights of Búzios field, of the write-offs related to the Co-Participation Agreements of Atapu and Sepia fields and of sales of properties in mature fields.

The company's total proved reserve resulted in 10,470 million boe in 2022, considering the variations above and the reduction from 2022 production of 860 million boe. Production refers to volumes that were previously included in our reserves and, therefore, does not consider natural gas liquids, since the reserve is estimated at a reference point prior to gas processing, except in the United States and Argentina. The production also does not consider volumes of injected gas, the production of Extended Well Tests in exploratory blocks and production in Bolivia, since the Bolivian Constitution does not allow the disclosure of reserves.

In 2021, we incorporated 1,969 million boe of proved reserves by revising previous estimates, including:

(i) addition of 1,376 million boe due to new projects, mainly in Búzios field and in other fields in the Santos and Campos Basins. The new projects in Búzios field were made possible due to the acquisition of the Transfer of Rights Surplus and the approval of Búzios Coparticipation Agreement;

(ii) addition of 429 million boe related to economic revisions, mainly due to the increase in oil prices; and

(iii) addition of 164 million boe arising from technical revisions, mainly due to good performance and increased production experience in reservoirs in the pre-salt layer of Santos Basin.

The additions in our proved reserves were partially offset by the reduction of 11 million boe due to sales of proved reserves.

The company's total proved reserve resulted in 9,878 million boe in 2021, considering the variations above and the reduction from 2021 production of 896 million boe. Production refers to volumes that were previously included in our reserves and, therefore, does not consider natural gas liquids, since the reserve is estimated at a reference point prior to gas processing, except in the United States and Argentina. The production also does not consider volumes of injected gas, the production of Extended Well Tests in exploratory blocks and production in Bolivia, since the Bolivian Constitution does not allow the disclosure of reserves.

In 2020, we incorporated 224 million boe of proved reserves by revising previous estimates, including:

(i) addition of 637 million boe arising from technical revisions, mainly due to good performance and increased production experience in reservoirs in the pre-salt layer of Santos Basin;

(ii) addition of 254 million boe due to approvals of new projects in the Santos and Campos Basins; and

(iii) reduction of 667 million boe related to economic revisions, mainly due to the decrease in oil prices.

In addition, we added 41 million boe to our proved reserves due to extensions and discoveries in the pre-salt of Santos Basin, and reduced 117 million boe due to sales of proved reserves.

The company's total proved reserve resulted in 8,816 million boe in 2020, considering the variations above and the reduction from 2020 production of 923 million boe. Production refers to volumes that were previously included in our reserves and, therefore, does not consider natural gas liquids, since the reserve is estimated at a reference point prior to gas processing, except in the United States and Argentina. The production also does not consider volumes of injected gas, the production of Extended Well Tests in exploratory blocks and production in Bolivia, since the Bolivian Constitution does not allow the disclosure of reserves.

The tables below present the volumes of proved developed and undeveloped reserves, net, that is, reflecting Petrobras' participation:


	2020
	Crude Oil	Synthetic Oil	Natural Gas	Synthetic Gas	Total oil and gas
	(mmbbl)		(bncf)		(mmboe)
*Net proved developed reserves ():**
Consolidated Entities
Brazil	4,858	−	5,714	−	5,810
South America, outside Brazil (1)	−	−	26	−	5
Total Consolidated Entities	4,858	−	5,740	−	5,814
Equity Method Investees
North America (1)	17	−	7	−	18
Total Equity Method Investees	17	−	7	−	18
Total Consolidated and Equity Method Investees	4,875	−	5,747	−	5,833
*Net proved undeveloped reserves ():**
Consolidated Entities
Brazil	2,676	−	1,833	−	2,982
South America, outside Brazil (1)	−	−	−	−	−
Total Consolidated Entities	2,676	−	1,833	−	2,982
Equity Method Investees
North America (1)	1	−	1	−	1
Total Equity Method Investees	1	−	1	−	1
Total Consolidated and Equity Method Investees	2,678	−	1,833	−	2,983
Total proved reserves (developed and undeveloped)	7,552	−	7,580	−	8,816

(1) South America oil reserves includes 21% of natural gas liquid (NGL) in proved developed reserves. North America oil reserves includes 6% of natural gas liquid (NGL) in proved developed reserves and 5% of NGL in proved undeveloped reserves.

(*) Apparent differences in the sum of the numbers are due to rounding off.

	2021
	Crude Oil	Synthetic Oil	Natural Gas	Synthetic Gas	Total oil and gas
	(mmbbl)		(bncf)		(mmboe)
*Net proved developed reserves ():**
Consolidated Entities
Brazil	4,711	10	5,591	18	5,656
South America, outside Brazil (1)	1	−	79	−	14
Total Consolidated Entities	4,712	10	5,669	18	5,670
Equity Method Investees
North America (1)	15	−	6	−	16
Total Equity Method Investees	15	−	6	−	16
Total Consolidated and Equity Method Investees	4,727	10	5,675	18	5,686
*Net proved undeveloped reserves ():**
Consolidated Entities
Brazil	3,695	−	2,865	−	4,173
South America, outside Brazil (1)	1	−	98	−	17
Total Consolidated Entities	3,696	−	2,963	−	4,190
Equity Method Investees
North America (1)	2	−	1	−	2
Total Equity Method Investees	2	−	1	−	2
Total Consolidated and Equity Method Investees	3,698	−	2,964	−	4,192
Total proved reserves (developed and undeveloped)	8,425	10	8,639	18	9,878

(1) South America oil reserves includes 24% of natural gas liquid (NGL) in proved developed reserves and 24% of NGL in proved undeveloped reserves. North America oil reserves includes 2% of natural gas liquid (NGL) in proved developed reserves and 3% of NGL in proved undeveloped reserves.

(*) Apparent differences in the sum of the numbers are due to rounding off.

	2022
	Crude Oil	Synthetic Oil	Natural Gas	Synthetic Gas	Total oil and gas
	(mmbbl)		(bncf)		(mmboe)
*Net proved developed reserves ():**
Consolidated Entities
Brazil	4,185	−	5,447	−	5,093
South America, outside Brazil (1)	1	−	91	−	16
Total Consolidated Entities	4,186	−	5,538	−	5,109
Equity Method Investees
North America (1)	14	−	5	−	15
Total Equity Method Investees	14	−	5	−	15
Total Consolidated and Equity Method Investees	4,200	−	5,543	−	5,124
*Net proved undeveloped reserves ():**
Consolidated Entities
Brazil	4,723	−	3,641	−	5,330
South America, outside Brazil (1)	1	−	82	−	14
Total Consolidated Entities	4,724	−	3,723	−	5,345
Equity Method Investees
North America (1)	2	−	1	−	2
Total Equity Method Investees	2	−	1	−	2
Total Consolidated and Equity Method Investees	4,726	−	3,724	−	5,347
Total proved reserves (developed and undeveloped)	8,926	−	9,267	−	10,470

(*) Apparent differences in the sum of the numbers are due to rounding off

(v) Standardized measure of discounted future net cash flows relating to proved oil and gas quantities and changes therein

The standardized measure of discounted future net cash flows, related to the above proved oil and gas reserves, is calculated in accordance with the requirements of Codification Topic 932 – Extractive Activities – Oil and Gas.

Estimated future cash inflows from production in Brazil are computed by applying the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Future price changes are limited to those provided by contractual arrangements existing at the end of each reporting year. Future development and production costs are those estimated future expenditures necessary to develop and produce year-end estimated proved reserves based on current costs, including abandonment costs, assuming continuing economic conditions. Estimated future income taxes (including future social contributions on net income - CSLL) are calculated by applying appropriate year-end statutory tax rates. The amounts presented as future income taxes expenses reflect allowable deductions considering statutory tax rates. Discounted future net cash flows are calculated using 10% mid-period discount factors. This discounting requires a year-by-year estimate of when the future expenditures will be incurred and when the reserves will be produced.

The valuation prescribed under Codification Topic 932 – Extractive Activities – Oil and Gas requires assumptions as to the timing and amount of future development and production costs. The calculations are made as of December 31 each year and should not be relied upon as an indication of Petrobras’ future cash flows or the value of its oil and gas reserves.

Standardized measure of discounted future net cash flows:

Standardized measure of discounted future net cash flows:
	Consolidated entities			Equity Method Investees
	Brazil	South America	Total	Equity Method Investees
December 31, 2022
Future cash inflows	983,826	837	984,663	1,581
Future production costs	(399,655)	(357)	(400,012)	(273)
Future development costs	(62,548)	(128)	(62,676)	(21)
Future income tax expenses	(178,412)	(88)	(178,500)	−
Undiscounted future net cash flows	343,211	264	343,475	1,287
10 percent midyear annual discount for timing of estimated cash flows (1)	(151,828)	(124)	(151,951)	(401)
Standardized measure of discounted future net cash flows	191,383	141	191,524	886
December 31, 2021
Future cash inflows	612,924	587	613,511	1,129
Future production costs	(264,158)	(261)	(264,419)	(329)
Future development costs	(44,027)	(107)	(44,134)	(28)
Future income tax expenses	(104,568)	(61)	(104,628)	−
Undiscounted future net cash flows	200,171	159	200,330	772
10 percent midyear annual discount for timing of estimated cash flows (1)	(85,391)	(70)	(85,461)	(303)
Standardized measure of discounted future net cash flows	114,780	89	114,869	470
December 31, 2020
Future cash inflows	333,248	69	333,317	667
Future production costs	(182,534)	(51)	(182,585)	(465)
Future development costs	(31,236)	(16)	(31,252)	(48)
Future income tax expenses	(46,862)	−	(46,862)	(79)
Undiscounted future net cash flows	72,616	2	72,618	75
10 percent midyear annual discount for timing of estimated cash flows (1)	(26,638)	−	(26,638)	(1)
Standardized measure of discounted future net cash flows	45,978	1	45,979	74

(1) Semiannual capitalization

Apparent differences in the sum of the numbers are due to rounding off.

Changes in discounted net future cash flows:


	Consolidated entities			Equity Method Investees
	Brazil	South America	Total	Equity Method Investees
Balance at January 1, 2022	114,780	89	114,869	470
Sales and transfers of oil and gas, net of production cost	(54,230)	(62)	(54,291)	(235)
Development cost incurred	6,883	31	6,913	29
Net change due to purchases and sales of minerals in place	(17,030)	−	(17,030)	−
Net change due to extensions, discoveries and improved recovery related costs	−	−	−	10
Revisions of previous quantity estimates	64,535	17	64,553	82
Net change in prices, transfer prices and in production costs	129,462	122	129,584	349
Changes in estimated future development costs	(23,317)	(39)	(23,356)	(4)
Accretion of discount	11,478	14	11,492	93
Net change in income taxes	(41,178)	(17)	(41,194)	−
Other - unspecified	−	(15)	(15)	92
Balance at December 31, 2022	191,383	141	191,524	886
Balance at January 1, 2021	45,978	1	45,979	74
Sales and transfers of oil and gas, net of production cost	(38,074)	(43)	(38,117)	(177)
Development cost incurred	6,035	44	6,079	37
Net change due to purchases and sales of minerals in place	(246)	−	(246)	−
Net change due to extensions, discoveries and improved recovery related costs	−	−	−	10
Revisions of previous quantity estimates	41,211	205	41,416	30
Net change in prices, transfer prices and in production costs	108,268	58	108,326	401
Changes in estimated future development costs	(19,900)	(119)	(20,019)	3
Accretion of discount	4,598	−	4,598	49
Net change in income taxes	(33,089)	(47)	(33,136)	48
Other - unspecified	−	(9)	(9)	(7)
Balance at December 31, 2021	114,780	89	114,869	470
Balance at January 1, 2020	88,121	69	88,190	1,412
Sales and transfers of oil and gas, net of production cost	(24,908)	(14)	(24,922)	(94)
Development cost incurred	5,664	3	5,666	57
Net change due to purchases and sales of minerals in place	(847)	−	(847)	(1,047)
Net change due to extensions, discoveries and improved recovery related costs	509	−	509	−
Revisions of previous quantity estimates	3,160	(35)	3,125	(10)
Net change in prices, transfer prices and in production costs	(54,606)	(145)	(54,751)	(375)
Changes in estimated future development costs	(4,716)	97	(4,618)	67
Accretion of discount	8,812	9	8,821	12
Net change in income taxes	24,788	24	24,812	51
Other - unspecified	-	(7)	(7)	1
Balance at December 31, 2020	45,978	1	45,979	74
Apparent differences in the sum of the numbers are due to rounding off.

Climate change (unaudited)

The Company considered the impacts related to its climate goals and climate risks in its Strategic Plan (PE). The assumptions and projections of the Plan baseline scenario are used for certain accounting estimates, including the value in use used in asset impairment tests (note 4.2).

i) Climate goals

In 2021, the Company assumed the ambition to neutralize emissions in activities under our control (Scopes 1 and 2) and influence partners to achieve the same ambition in non-operated assets, within a period compatible with the Paris Agreement (net zero ambitions). However, the Company recognizes that there are relevant technological gaps for achieving its net zero ambitions.

The central objective of the Paris Agreement is to strengthen the global response to the threat of climate change by keeping the global temperature rise this century well below 2°C compared to pre-industrial levels and by striving to limit the temperature rise to 1.5 °C.

The Company's net zero ambition adds to the portfolio of sustainability commitments with a horizon of 2025 and 2030, where 6 commitments are related to the mitigation of greenhouse gases (GHG):

• Reduction of absolute operating emissions by 30% by 2030 (compared to 2015);

• Zero routine flaring by 2030, as per the World Bank's Zero Routine Flaring initiative;

• Reinjection of 80 MM ton CO₂ by 2025 in CCUS (Carbon Capture, Usage and Storage) projects;

• Greenhouse Gas (GHG) intensity in the E&P segment: achieve portfolio intensity of 15 kgCO₂e/boe by 2025, maintained at 15 kgCO₂e/boe by 2030;

• GHG intensity in the Refining segment: Achieve an intensity of 36 kgCO₂e/CWT by 2025 and 30 kgCO₂e/CWT by 2030; and

• Consolidation of the 55% reduction (compared to 2015) in the intensity of methane emissions in the upstream segment by 2025, reaching 0.29 t CH₄/thousand tHC.

The above commitments do not constitute guarantees of future performance by the Company and are subject to assumptions that may not materialize and to risks and uncertainties that are difficult to predict.

The Company's commitments to reduce GHG emissions, as well as the ambition to zero its net operating GHG emissions (scopes 1 and 2) up to 2050, were considered in the preparation of PE 23-27, plan updated every year.

ii) Climate risks

Risk of transition to a low-carbon economy

The risk of the transition to a low-carbon economy is mainly reflected in the price of Brent, demand for products and the price of carbon.

The Baseline scenario of the PE contemplates climate and environmental policies that are in line with the goals already announced, in their most general aspects. In such a scenario, there is greater concern with mobility and air quality in large urban centers. More direct solutions for the energy transition, driven by large cities and driven by population pressure, characterize this scenario. The global energy matrix has undergone important changes, especially with regard to the participation of coal and renewable sources. The result of this scenario is a more diversified energy matrix, with growth in the share of renewables and commodity prices in line with what has been observed historically.

In this context, the Base scenario considers an oil price range ranging from an average of US$ 85/bbl in 2023 and reaching US$ 55/bbl from 2030 onwards, that is, price expectations similar to the Announced Pledges scenario (APS) by the International Energy Agency, which is aligned with a 50% probability of keeping the temperature increase below 1.7°C by 2100. The APS scenario assumes that all aspirational targets announced by governments are met on time and in full, including its long-term net zero and energy access targets.

The valuation of the portfolio in the Base scenario of the Company used for approval of the Strategic Plan is carried out without the incidence of the carbon price. Despite the publication of Decree No. 11,075/2022, the definition of the instrument to be adopted in Brazil is still being discussed by the federal legislature (PL 412-2022), and the regulated sectors and segments will still be defined within the scope of the national executive power. Thus, at the moment, there are uncertainties regarding the functioning of a future carbon market in Brazil, due to the lack of sufficient and reliable information about the future intentions of regulators that allow considering the impact of the price of carbon in the valuation of our portfolio for accounting estimates purposes. More than 97% of the Company's operational GHG emissions occur in Brazilian territory.

When simulating the net present value of our portfolio in the Base scenario, through sensitivity to the price of Brent and the price of carbon contained in the APS scenario of the International Energy Agency, it was verified that there would be a 23% total positive impact when compared to the value calculated based on the internal assumptions detailed above.

The simulation considers the impact of the Brent price in the APS scenario only on the E&P segment and the maintenance of margins in the other segments. Regarding the effect of the carbon price in the simulation, the carbon price of the APS scenario was adopted, applied based on assumptions referenced in international carbon markets in operation, since there are still uncertainties regarding the functioning of a future carbon market in Brazil. In the APS scenario, a carbon price range of US$ 40/bbl in 2030 is considered, going to US$ 110/bbl in 2040 and reaching US$ 160/bbl from 2050.

Physical Risks

The company identifies and monitors the physical parameters considered potentially more susceptible to variations that may cause changes in standards in the operating conditions of its assets, such as water availability for our refineries and thermoelectric plants, and wave, wind and ocean current patterns for our platforms .

For environmental variables in the oceanic region, we currently rely on technological partners to simulate atmospheric conditions, ocean circulation and future waves under the effect of climate projections in the Santos, Campos and Espírito Santo Basins, which concentrate approximately 90% of current production of the company. For the studied offshore meteoceanographic variables, in general, over the useful life of our assets, the magnitude of the impacts is within the safety parameters considered in our projects.

The operating conditions of the assets affect certain accounting estimates of the Company.