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

12 Months Ended

Dec. 31, 2023

Supplementary Information On Oil And Gas Exploration And Production

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

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, 2023, 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 the USA, in which Murphy Exploration & Production Company ("Murphy") has an 80% stake and Petrobras America Inc ("PAI") a 20% stake. The Company reports its reserves in Brazil, United States of America and Argentina. Volumes in Bolivia are not registered as the Constitution of this country does not allow. 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 27, the Company uses the successful efforts method of accounting for appraisal and development costs of crude oil and natural gas production. In addition, notes 24 and 25 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:


	Consolidated entities
	Brazil	Abroad			Total	Equity Method Investees
		South America	Others	Total		Equity Method Investees
December 31, 2023
Unproved oil and gas properties	3,764	61	−	61	3,825	−
Proved oil and gas properties	82,396	243	−	243	82,639	607
Support Equipment	103,285	758	1	759	104,044	−
Gross Capitalized costs	189,444	1,062	1	1,063	190,507	607
Depreciation, depletion and amortization	(63,003)	(811)	(1)	(812)	(63,815)	(289)
Net capitalized costs	126,442	251	−	251	126,692	318
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

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
	Brazil	Abroad		Total	Equity Method Investees
		South America	Total		Equity Method Investees
December 31, 2023
Acquisition costs:
Proved	−	−	−	−	−
Unproved	146	−	−	146	−
Exploration costs	862	11	11	873	10
Development costs	10,929	53	53	10,982	37
Total	11,937	64	64	12,001	47
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

(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, 2023, 2022 and 2021 are shown in the following table. The Company transfers substantially all of its Brazilian crude oil and gas production to the RT&M and G&LCE segments, respectively, 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.


	Consolidated entities						Equity Method Investees
	Brazil	Abroad				Total
		South America	North America	Others	Total
December 31, 2023
Net operation revenues:
Sales to third parties	631	136	−	−	136	767	159
Intersegment	66,113	−	−	−	−	66,113	−
	66,744	136	−	−	136	66,880	159
Production costs	(16,946)	(63)	−	−	(63)	(17,009)	(36)
Exploration expenses	(981)	(1)	−	−	(1)	(982)	−
Depreciation, depletion and amortization	(10,186)	(44)	−	−	(44)	(10,230)	(26)
Impairment of oil and gas properties	(2,105)	−	−	−	−	(2,105)	(75)
Other operating expenses	(2,504)	(15)	(8)	(1)	(24)	(2,528)	(25)
Results before income tax expenses	34,023	12	(8)	(1)	3	34,026	(3)
Income tax expenses	(11,568)	(4)	3	1	(1)	(11,569)	−
Results of operations (excluding corporate overhead and interest costs)	22,455	8	(5)	(1)	2	22,457	(3)
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

(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 2023, 2022 and 2021 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):


	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	Total
At January 1, 2023	8,908	2	−	8,910	16	8,926
Extensions and discoveries	95	−	−	95	−	95
Revisions of previous estimates	1,140	−	−	1,140	2	1,142
Sales of reserves	(147)	−	−	(147)	−	(147)
Production for the year	(786)	−	−	(786)	(2)	(789)
Reserves at December 31, 2023	9,210	2	−	9,212	16	9,228
At January 1, 2022	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
At January 1, 2021	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
(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.
In 2023, we standardized the conversion between gas and oil equivalent to 5,614.65 ft3 = 1 boe, which is equivalent to the conversion used in contracts in Brazil. Quantities from previous years were restated with the new conversion.

A summary 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	Natural Gas in North America	Total
At January 1, 2023	8,504	173	−	8,677	6	8,683
Extensions and discoveries	779	15	−	794	−	794
Revisions of previous estimates	673	(5)	−	668	1	669
Sales of reserves	(47)	−	−	(47)	−	(47)
Production for the year	(573)	(20)	−	(594)	(1)	(595)
Reserves at December 31, 2023	9,335	163	−	9,498	7	9,504
At January 1, 2022	7,912	177	17	8,106	7	8,113
Revisions of previous estimates	1,560	16	−	1,575	−	1,575
Sales of reserves ⁽¹⁾	(382)	−	(15)	(397)	(1)	(398)
Production for the year	(586)	(20)	(1)	(606)	(1)	(607)
Reserves at December 31, 2022	8,504	173	−	8,677	6	8,683
At January 1, 2021	7,062	26	−	7,088	8	7,095
Extensions and discoveries	−	−	−	−	−	−
Revisions of previous estimates	1,512	167	18	1,697	−	1,697
Sales of reserves	(14)	−	−	(14)	−	(14)
Production for the year	(647)	(16)	(1)	(664)	(1)	(666)
Reserves at December 31, 2021	7,912	177	17	8,106	7	8,113
(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.
In 2023, we standardized the conversion between gas and oil equivalent to 5,614.65 ft3 = 1 boe, which is equivalent to the conversion used in contracts in Brazil. Quantities from previous years were restated with the new conversion.

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 35% of our total proved reserves of natural gas as of December 31, 2023.

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 2023, 2022 and 2021:


	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	Total
At January 1, 2023	10,423	33	−	10,455	17	10,473
Extensions and discoveries	233	3	−	236	−	237
Revisions of previous estimates	1,260	(1)	−	1,259	2	1,262
Sales of reserves	(155)	−	−	(155)	−	(155)
Production for the year	(888)	(4)	−	(892)	(2)	(894)
Reserves at December 31, 2023	10,873	31	−	10,904	17	10,921
At January 1, 2022	9,816	33	13	9,862	18	9,880
Revisions of previous estimates	1,983	3	−	1,986	3	1,989
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	33	−	10,455	17	10,473
At January 1, 2021	8,792	5	−	8,797	19	8,816
Extensions and discoveries	−	−	−	−	1	1
Revisions of previous estimates	1,923	32	14	1,969	2	1,971
Sales of reserves	(11)	−	−	(11)	−	(11)
Production for the year	(888)	(3)	(1)	(892)	(3)	(896)
Reserves at December 31, 2021	9,816	33	13	9,862	18	9,880
(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.
In 2023, we standardized the conversion between gas and oil equivalent to 5,614.65 ft3 = 1 boe, which is equivalent to the conversion used in contracts in Brazil. Quantities from previous years were restated with the new conversion.

In 2023, we incorporated 1,262 million boe of proved reserves by revising previous estimates, including:

(i) addition of 1,092 million boe arising from the good performance of assets, mainly in Búzios, Tupi and Atapu fields, in the Santos Basin; and

(ii) addition of 170 million boe due to new projects and other revisions.

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

In addition, we incorporated 237 million boe from discoveries and extensions, mainly due to the declaration of commerciality of Raia Manta and Raia Pintada fields (non-operated), in the Campos Basin.

Moreover, proved reserves were reduced by 155 million boe, resulting from sales.

The Company's total proved reserve resulted in 10,921 million boe in 2023, considering the variations above and the reduction from 2023 production of 894 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 of America 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 registration of reserves by the Company.

In 2022, we incorporated 1,989 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 710 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 10,473 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 of America 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 registration of reserves by the Company.

In 2021, we incorporated 1,971 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 166 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 9,880 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 of America 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 registration of reserves by the Company.

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


	2023
	Crude Oil	Synthetic Oil	Natural Gas	Synthetic Gas	Total oil and gas
	(mmbbl)		(bncf)		(mmboe)
*Net proved developed reserves ^():**
Consolidated Entities
Brazil	4,710	−	5,522	−	5,694
South America, outside Brazil ⁽¹⁾	1	−	92	−	17
Total Consolidated Entities	4,711	−	5,614	−	5,711
Equity Method Investees
North America ⁽¹⁾	14	−	6	−	15
Total Equity Method Investees	14	−	6	−	15
Total developed Consolidated and Equity Method Investees	4,726	−	5,620	−	5,727
*Net proved undeveloped reserves ^():**
Consolidated Entities
Brazil	4,500	−	3,814	−	5,179
South America, outside Brazil ⁽¹⁾	1	−	70	−	13
Total Consolidated Entities	4,501	−	3,884	−	5,193
Equity Method Investees
North America ⁽¹⁾	2	−	1	−	2
Total Equity Method Investees	2	−	1	−	2
Total undeveloped Consolidated and Equity Method Investees	4,503	−	3,885	−	5,194
Total proved reserves (developed and undeveloped)	9,228	−	9,504	−	10,921
(1) South America oil reserves includes 25% of natural gas liquid (NGL) in proved developed reserves and 26% of NGL in proved undeveloped reserves. North America oil reserves includes 6% of natural gas liquid (NGL) in proved developed reserves and 7% of NGL in proved undeveloped reserves.
(*) Apparent differences in the sum of the numbers are due to rounding.
In 2023, we standardized the conversion between gas and oil equivalent to 5,614.65 ft3 = 1 boe, which is equivalent to the conversion used in contracts in Brazil. Quantities from previous years were restated with the new conversion.

	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	−	5,097	−	5,093
South America, outside Brazil (1)	1	−	91	−	17
Total Consolidated Entities	4,186	−	5,188	−	5,110
Equity Method Investees
North America (1)	14	−	5	−	15
Total Equity Method Investees	14	−	5	−	15
Total developed Consolidated and Equity Method Investees	4,200	−	5,193	−	5,125
*Net proved undeveloped reserves ():**
Consolidated Entities
Brazil	4,723	−	3,407	−	5,330
South America, outside Brazil (1)	1	−	82	−	15
Total Consolidated Entities	4,724	−	3,489	−	5,346
Equity Method Investees
North America (1)	2	−	1	−	2
Total Equity Method Investees	2	−	1	−	2
Total undeveloped Consolidated and Equity Method Investees	4,726	−	3,490	−	5,348
Total proved reserves (developed and undeveloped)	8,926	−	8,683	−	10,473
(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 4% of NGL in proved undeveloped reserves.
(*) Apparent differences in the sum of the numbers are due to rounding.
In 2023, we standardized the conversion between gas and oil equivalent to 5,614.65 ft3 = 1 boe, which is equivalent to the conversion used in contracts in Brazil. Quantities from previous years were restated with the new conversion.

	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	5,232	17	5,656
South America, outside Brazil (1)	1	−	79	−	15
Total Consolidated Entities	4,712	10	5,310	17	5,671
Equity Method Investees
North America (1)	15	−	6	−	16
Total Equity Method Investees	15	−	6	−	16
Total developed Consolidated and Equity Method Investees	4,727	10	5,316	17	5,687
*Net proved undeveloped reserves ():**
Consolidated Entities
Brazil	3,695	−	2,681	−	4,173
South America, outside Brazil (1)	1	−	98	−	18
Total Consolidated Entities	3,696	−	2,779	−	4,191
Equity Method Investees
North America (1)	2	−	1	−	2
Total Equity Method Investees	2	−	1	−	2
Total undeveloped Consolidated and Equity Method Investees	3,698	−	2,780	−	4,193
Total proved reserves (developed and undeveloped)	8,425	10	8,096	17	9,880
(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.
In 2023, we standardized the conversion between gas and oil equivalent to 5,614.65 ft3 = 1 boe, which is equivalent to the conversion used in contracts in Brazil. Quantities from previous years were restated with the new conversion.

(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:


	Consolidated entities			Equity Method Investees
		Abroad
	Brazil	South America	Total
December 31, 2023
Future cash inflows	819,428	650	820,078	1,213
Future production costs	(348,787)	(354)	(349,142)	(191)
Future development costs	(64,121)	(113)	(64,235)	(13)
Future income tax expenses	(140,774)	(43)	(140,818)	−
Undiscounted future net cash flows	265,745	139	265,884	1,009
10 percent midyear annual discount for timing of estimated cash flows ⁽¹⁾	(120,216)	(46)	(120,262)	(319)
Standardized measure of discounted future net cash flows	145,529	93	145,622	691
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
(1) Semiannual capitalization
Apparent differences in the sum of the numbers are due to rouding.

Changes in discounted net future cash flows:


	Consolidated entities			Equity Method Investees
		Abroad
	Brazil	South America	Total
Balance at January 1, 2023	191,383	141	191,524	886
Sales and transfers of oil and gas, net of production cost	(49,797)	(54)	(49,851)	(123)
Development cost incurred	10,929	53	10,982	37
Net change due to purchases and sales of minerals in place	(3,894)	−	(3,894)	−
Net change due to extensions, discoveries and improved recovery related costs	5,858	19	5,876	11
Revisions of previous quantity estimates	31,616	3	31,619	82
Net change in prices, transfer prices and in production costs	(63,907)	(97)	(64,004)	(201)
Changes in estimated future development costs	(16,409)	(27)	(16,436)	(17)
Accretion of discount	19,138	20	19,159	68
Net change in income taxes	20,611	30	20,641	−
Other - unspecified	−	5	5	(53)
Balance at December 31, 2023	145,529	93	145,622	691
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
Apparent differences in the sum of the numbers are due to rounding.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing, adequately maintaining and assessing the effectiveness of internal control over financial reporting. Such internal control is a process designed by, or under the supervision of our CEO and CFO, and effected by our board of directors, management and other employees.

The internal control over financial reporting is designed to provide reasonable assurances regarding the reliability of financial reporting and of the preparation of our consolidated financial statements for external purposes, in accordance with IFRS, as issued by the IASB.

Due to its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. In addition, projections of any evaluation of effectiveness of internal control over financial reporting to future periods are subject to the risk of becoming inadequate because of changes in its conditions and assumptions.

Our management has assessed the effectiveness of our internal control over financial reporting as of December 31, 2023 based on the criteria established in “Internal Controls – Integrated Framework (2013)” issued by the Committee of Sponsoring Organizations of Treadway Commission (“COSO”). Our management has concluded that our internal control over financial reporting was effective.

/s/ Jean Paul Prates

Jean Paul Prates

Chief Executive Officer

/s/ Sergio Caetano Leite

Sergio Caetano Leite

Chief Financial Officer and Chief Investor Relations Officer

Independent auditor's report on the consolidated financial statements

KPMG Auditores Independentes Ltda.

Rua do Passeio, 38 - Setor 2 - 17º andar - Centro

20021-290 - Rio de Janeiro/RJ - Brasil

Caixa Postal 2888 - CEP 20001-970 - Rio de Janeiro/RJ - Brasil

Telefone +55 (21) 2207-9400

www.kpmg.com.br

Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors

Petróleo Brasileiro S.A. - Petrobras

Rio de Janeiro

Opinions on the Consolidated Financial Statements and Internal Control Over Financial Reporting

We have audited the accompanying consolidated statements of financial position of Petróleo Brasileiro S.A. – Petrobras and subsidiaries (“the Company”) as of December 31, 2023 and 2022, the related consolidated statements of income, comprehensive income, changes in shareholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2023, and the related notes (collectively, the “consolidated financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

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

Basis for Opinions

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

KPMG Auditores Independentes Ltda., uma sociedade simples brasileira, de responsabilidade limitada e firma-membro da organização global KPMG de firmas-membro independentes licenciadas da KPMG International Limited, uma empresa inglesa privada de responsabilidade limitada.

KPMG Auditores Independentes Ltda., a Brazilian limited liability company and a member firm of the KPMG global organization of independent member firms affiliated with KPMG International Limited, a private English company limited by guarantee.

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

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

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Assessment of the measurement of the defined benefit obligations for pension and health care plans

As discussed in notes 4.4 and 18.3 to the consolidated financial statements, the Company sponsors defined benefit pension and health care plans that provide supplementary retirement benefits and medical care to its employees. As of December 31, 2023, the defined benefit obligations for these pension and health care plans were US$ 16,382 million. The measurement of the Company’s defined benefit obligations with respect to these plans requires the determination of certain actuarial assumptions. These assumptions include the discount rates and projected medical and hospital costs. The Company hires an external actuarial firm to assist in the process of determining the actuarial assumptions and the valuation of the defined benefit obligations for its pension and health care plans.

We identified the assessment of the measurement of the defined benefit obligations for the pension and health care plans as a critical audit matter. Subjective auditor judgment was required because changes to the discount rates and projected medical and hospital costs used to determine the defined benefit obligations can cause significant changes to the measurement of the defined benefit obligations for the pension and health care plans.

The following are the primary procedures we performed to address this critical audit matter:

we evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s process for determining the defined benefit obligations for pension and health care plans. This included controls related to the determination, review and approval of the discount rates and projected medical and hospital costs;

we assessed the scope of the work, competency, and objectivity of the external actuarial firm hired by the Company to assist in the process of determining the actuarial assumptions and the measurement of the defined benefit obligations for the pension and health care plans. This included assessing the nature and scope of the work performed by the external actuarial firm and its qualifications and professional experience; and

we involved actuarial professionals with specialized skills and knowledge, who assisted in evaluating the Company’s discount rates and projected medical and hospital costs including comparisons to data obtained from external sources.

Evaluation of the impairment testing of exploration and production cash generating units

As discussed in notes 4.2.1, 4.2.2 and 26 to the consolidated financial statements, for the purposes of impairment testing, the Company identifies its cash generating units (“CGUs”), estimates the recoverable amount of these CGUs and compares the recoverable amount with the carrying amount of these CGUs. The carrying amount before the impairment testing of the exploration and production CGUs as of December 31, 2023 was US$ 8,332 million. For the year ended December 31, 2023, the amount of impairment losses recognized in relation to the exploration and production CGUs was US$ 2,217 million.

We identified the evaluation of the impairment testing of exploration and production CGUs as a critical audit matter. A high degree of complexity and subjectivity of auditor judgment was involved in evaluating the Company’s determination of these CGUs and the estimate of the recoverable amount. The determination of exploration and production CGUs requires auditor judgment in the consideration of operational factors that impact the interdependencies between oil and gas assets. These interdependencies alter the aggregation or segregation of the oil and gas assets into CGUs. The expected future cash flows used to determine the recoverable amount depend on certain assumptions about the future including average Brent oil and natural gas prices; exchange rate (Brazilian Real / US Dollar); capital and operating expenditures and volume and timing of recovery of the oil and gas reserves. The recoverable amount is also sensitive to changes in the discount rate. The assessment of these assumptions required significant auditor judgment.

The following are the primary procedures we performed to address this critical audit matter:

we evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s impairment assessment process. These included controls related to the review and approval of the Company’s determination of the CGUs and of the key assumptions used to estimate the recoverable amount;

we assessed the operational factors considered by the Company for changes in exploration and production CGUs during the year, when determining these changes by comparing to information obtained from internal and external sources;

we evaluated the Company’s internally prepared projections of recovery of oil and gas reserves, by comparing them with estimated volumes certified by an external reservoir specialist hired by the Company and, for a selection of CGUs, with historical production;

we evaluated the scope of the work, competency, and objectivity of the internal engineers responsible for the estimate of the oil and gas reserves, as well as the external reservoir specialist hired by the Company that certified the estimated reserve volumes. This included assessing the nature and scope of the work they were engaged to perform and their qualifications and professional experience;

we evaluated, for a selection of CGUs, the Company’s projected future capital and operating expenditures by comparing these projections with the latest approved business and management plan and long-term budgets;

we evaluated the Company’s ability to accurately project cash flows by comparing, for a selection of CGUs, the prior years’ estimated cash flows for the year ended December 31, 2023 with actual cash flows in this year; and

we involved valuation professionals with specialized skill and knowledge, who assisted in evaluating certain assumptions used in the impairment testing such as the discount rates, average Brent oil and natural gas prices and the exchange rates by comparing them against available external market data.

Evaluation of the estimate of the provision for decommissioning costs

As discussed in notes 4.6 and 20 to the consolidated financial statements the Company records a provision for decommissioning costs which reflects its obligations to restore the environment and dismantle and remove oil and gas production facilities upon abandonment. As of December 31, 2023, the carrying amount of the provision for decommissioning costs was US$ 23,202 million. The Company’s estimate of the provision for decommissioning costs includes assumptions in relation to the nature and extent of the environmental restoration and the dismantlement and removal work as well as the cost and timing of this work.

We identified the evaluation of the estimate of the provision for decommissioning costs as a critical audit matter. Subjective auditor judgment was necessary to evaluate the key assumptions used in the estimate such as the extent of the decommissioning work that will be required by contract and regulations, the criteria to be met when the decommissioning actually occurs and the costs and related timing of the future payments that will be incurred in the decommissioning process.

The following are the primary procedures we performed to address this critical audit matter:

we evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s process to estimate the provision for decommissioning costs. This included controls related to the determination, review and approval of the key assumptions, including estimates of the timing of abandonment and estimated costs of decommissioning;

we assessed the estimates of timing until abandonment used by the Company by comparing the production curves and life of the oil and gas reserves used with estimated reserve volumes certified by the external reservoir specialist hired by the Company;

we assessed the estimated costs of decommissioning by comparing certain key assumptions with external market data;

we evaluated the scope of the work, competency, and objectivity of the internal engineers that estimated the production curves and life of the oil and gas reserves and the external reservoir specialist hired by the Company that certified the estimated reserve volumes. This included assessing the nature and scope of the work they were engaged to perform and their qualifications and professional experience; and

we evaluated the Company´s ability to accurately forecast costs of decommissioning work, by comparing a selection of actual expenditure incurred with the decommissioning of oil and gas production facilities during the year to the Company´s forecasts of that expenditure at the prior year-end.

/s/ KPMG Auditores Independentes Ltda.

KPMG Auditores Independentes Ltda.

We have served as the Company’s auditor since 2017.

Rio de Janeiro – Brazil

April 11, 2024