Centaurus Energy Inc. — Audit Report / Information 2020

Jul 15, 2021

==> picture [187 x 43] intentionally omitted <==

STATEMENT OF RESERVES DATA AND OTHER OIL & GAS INFORMATION Year Ended December 31, 2020

July 6, 2021

2

REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

The statement of reserves data and other oil and gas information (the "Statement") set forth below is dated July 6, 2021. The effective date of the Statement is December 31, 2020. The preparation date is July 6, 2021.

Disclosure of Reserves Data

The Corporation engaged GLJ to provide an evaluation, as at December 31, 2020, of the Corporation's oil and natural gas reserves attributable to all of Centaurus´ properties, which are located exclusively in Argentina. The GLJ Report also presents the estimated net present value of future net revenue of Centaurus´ properties before and after taxes, at various discount rates.

The reserves data set forth below (the "Reserves Data") is based upon the GLJ Report. The GLJ Report has been prepared in accordance with the standards contained in the COGE Handbook and the reserves definitions contained in NI 51-101 and the COGE Handbook. The Reserves Data conforms to the requirements of NI 51-101. The report in the form of Form 51-101F2 Report on Reserves Data by Independent Qualified Reserves Evaluator or Auditor as provided by GLJ is attached as Schedule "A" hereto. The report in the form of Form 51-101F3 Report of Management and Directors on Oil and Gas Disclosure as provided by the management of the Corporation is attached hereto as Schedule "B".

The GLJ Report is based on certain factual data supplied by the Corporation and the opinion of GLJ based on reasonable practices in the industry. The extent and character of ownership and all factual data pertaining to the Corporation's petroleum properties and contracts (except for certain information residing in the public domain) were supplied by the Corporation to GLJ and accepted without any further investigation. GLJ accepted this data as presented and neither title searches nor field inspections were conducted.

The evaluation of future revenue is stated after royalties, development costs, production costs and well abandonment costs but before consideration of the deduction of future income tax expenses (unless otherwise noted in the tables), indirect costs such as administrative, overhead and other miscellaneous expenses. The estimated future net revenue contained in the following tables does not necessarily represent the fair market value of the reserves associated with Centaurus´ assets and properties. There is no assurance that the forecast price and cost assumptions will be attained and variances could be material. Other assumptions and qualifications relating to costs and other matters are summarized in the notes to the following tables. The recovery and reserves estimates for Centaurus´ assets and properties described herein are estimates only and there is no guarantee that the estimated reserves will be recovered. The actual reserves for Centaurus´ assets and properties may be greater or inferior than those calculated herein.

3

Reserves Data (Forecast Prices and Costs)

The following tables provide a summary of the Corporation's oil and gas reserves and net present value of future net revenue at December 31, 2020 using forecast prices and costs. Amounts shown are in USD.

Summary of Oil and Gas Reserves and Net Present Values of Future Net Revenue at December 31, 2020

Forecast Prices and Costs USD

Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved Plus Probable Possible(3) Total Proved Plus Probable PlusPossible(3)	Light/Medium Crude Oil Gross (Mbbl) Net (Mbbl) 308 250 533 451 0 0	Light/Medium Crude Oil Gross (Mbbl) Net (Mbbl) 308 250 533 451 0 0					Reserves		Total Reserves Gross (Mboe) Net (Mboe)
				Tight Oil(1)			Conventional Natural Gas Gross (MMcf) Net (MMcf)	Shale Gas(1) Gross (MMcf) Net (MMcf)
		Net (Mbbl) 250 451 0		Gross (Mbbl) 1,062 0 3,372	Net (Mbbl) 903 0 2,866
							512 420 213 177 0 0	0 0 0 0 223 197	1,455 1,223 569 480 3,409 2,899
	841 3,331	701 2,688		4,434 12,611	3,769 10,719		725 597 4,753 3,862	223 197 2,716 2,390	5,434 4,602 17,186 14,450
	4,172 2,687	3,389 2,200		17,045 10,906	14,488 9,270		5,478 4,459 2,484 2,022	2,940 2,587 2,985 2,627	22,620 19,052 14,504 12,245
	6,859	5,589		27,951	23,758		7,962 6,480	5,925 5,214	37,124 31,297

	Net Present Values of Future Net Revenue USD
Reserves Category Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved Plus Probable Possible(3) Total Proved Plus Probable PlusPossible(3)	Before Income Taxes Discounted at (%/year) After Income Taxes Discounted at (%/year) Unit Value Before tax Discounted at 10%(2)
	0% MM 5% MM 10% MM 15% MM 20% MM 0% MM 5% MM 10% MM 15% MM 20% MM $/BOE
	3.1 6.0 7.3 7.8 7.8 3.1 6.0 7.3 7.8 7.8 5.96 2.7 2.2 1.8 1.5 1.2 2.7 2.2 1.8 1.5 1.2 3.81 28.3 11.2 1.1 (5.0) (8.8) 28.3 11.2 1.1 (5.0) (8.8) 0.37
	34.1 19.4 10.2 4.2 0.3 34.1 19.4 10.2 4.2 0.3 2.22 294.0 146.9 74.5 35.5 13.0 213.5 98.8 42.4 12.3 (4.6) 5.16
	328.1 166.4 84.7 39.7 13.3 247.6 118.2 52.6 16.6 (4.3) 4.45 441.5 230.6 140.1 93.9 67.2 308.7 157.5 92.8 60.1 41.4 11.44
	769.6 397.0 224.8 133.6 80.5 556.3 275.7 145.4 76.7 37.0 7.18

Notes:

(1) These are unconventional Vaca Muerta Shale reserves at CASE and the costs incurred to December 31, 2020 are included in Property, plant and equipment in the Corporation’s consolidated financial statements.

(2) Unit values are based on Corporation Net Reserves.

(3) Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

4

Total Future Net Revenue (Undiscounted) at December 31, 2020

Forecast Prices and Costs USD

						Future		Future
					Well	Net		Net
					Abandonment	Revenue		Revenue
					and	Before		After
			Operating	Developmen	Reclamation	Income	Income	Income
	Revenue	Royalties	Costs	t Costs	Costs	Taxes	Taxes	Taxes
Reserves Category	MM	MM	MM	MM	MM	MM	MM	MM
Total Proved Reserves	272.7	41.7	108.4	72.1	16.4	34.1	0	34.1
Total Proved Plus Probable
Reserves	1,203.1	188.9	353.1	310.0	23.0	328.1	80.5	247.6
Total Proved Plus Probable Plus
Possible Reserves(1)	2,017.1	315.4	511.7	395.5	25.0	769.6	213.2	556.3

Note:

(1) Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

Pricing Assumptions

The forecast cost and price assumptions relating to the Argentine reserves assume increases in wellhead selling prices and take into account inflation with respect to future operating and capital costs.

GLJ employed the following pricing, exchange rate and inflation rate assumptions as of December 31, 2020 in the GLJ Report in estimating reserves data using forecast prices and costs. GLJ is independent of the Corporation.

Summary of Pricing and Inflation Rate Assumptions at December 31, 2020 Forecast Prices and Costs

Year 2021 ............................................... 2022 ............................................... 2023 ............................................... 2024 ............................................... 2025 ............................................... 2026 ............................................... 2027 ............................................... 2028 ............................................... 2029 ............................................... 2030 ............................................... 2031 ............................................... 2032 ............................................... 2033 ............................................... 2034 ............................................... 2035 ............................................... 2036+ .............................................	World Brent Price USD/bbl 49.42 52.85 56.04 57.87 59.00 60.15 61.33 62.53 63.75 65.03 66.33 67.66 69.01 70.39 71.80 +2.0%/yr	Argentina Domestic Gas Price USD/ Mmbtu 2.02 2.05 2.09 2.13 2.17 2.21 2.26 2.30 2.35 2.40 2.45 2.49 2.54 2.60 2.65 +2.0%/yr

Notes:

(1) The price forecast used for this evaluation is based on industry consensus pricing for January 1, 2021. Industry consensus pricing is based on the average price forecasts from the three largest reserves evaluation companies in Canada – GLJ Petroleum Consultants, McDaniel and Associates and Sproule Associates Limited.

(2) GLJ has assumed that the Argentine crude oil and condensate price will be correlated to Brent prices, with adjustments for quality and transportation. (3) Commodity prices escalation at 2% per year after 2036.

(4) All costs escalate at 2% per year from 2021.

(5) Gas price represents industrial contract prices received. Weighted average historical prices realized by the Corporation for year ended December 31, 2020

5

from its oil and gas properties was $35.30/bbl for crude oil and $1.99/Mcf for natural gas.

• (6) Well abandonment and reclamation costs for all existing wells and future wells associated with properties to which reserves have been assigned have been included at the property level. Additional abandonment and reclamation costs associated with wells associated with properties not assigned reserves have not been included in this analysis.

• (7) The extent and character of all factual data supplied to GLJ were accepted by GLJ as represented. No field inspection was conducted.

Reconciliation of Changes in Reserves

The following tables set out the reconciliation of the Corporation's gross reserves as at December 31, 2020 compared to December 31, 2019 based on forecast prices and costs by principal product type.

FACTORS	-------------- Light and Medium Crude Oil --------------	-------------- Light and Medium Crude Oil --------------	-------------- Light and Medium Crude Oil --------------	--------------------	Tight Crude Oil	----------------------
			Proved Plus			Proved Plus
	Proved	Probable	Probable	Proved	Probable	Probable
	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)	(Mbbl)
December 31, 2019	2,554	2,731	5,285	2,612	7,720	10,331
Discoveries	-	-	-	-	-	-
Extensions(1)	-	-	-	1,556	4,836	6,392
Infill Drilling(1)	-	-	-	-	-	-
Improved Recovery(1)	-	-	-	-	-	-
Technical Revisions	(843)	1,187	344	624	47	671
Acquisitions	-	-	-	-	-	-
Dispositions	(194)	(415)	(609)	-	-	-
Economic Factors	(272)	(173)	(445)	(13)	8	(5)
Production	(404)	-	(404)	(344)	-	(344)
December 31, 2020	841	3,331	4,172	4,434	12,611	17,045

FACTORS	---------------------------- NGLs ----------------------------	---------------------------- NGLs ----------------------------	---------------------------- NGLs ----------------------------	------------- Conventional Natural Gas ---------------	------------- Conventional Natural Gas ---------------	------------- Conventional Natural Gas ---------------
			Proved Plus			Proved Plus
	Proved	Probable	Probable		Probable	Probable
	(Mbbl)	(Mbbl)	(Mbbl)	Proved (MMcf)	(MMcf)	(MMcf)
December 31, 2019	-	-	-	2,936	3,311	6,247
Discoveries	-	-	-	-	-	-
Extensions(1)	-	-	-	-	-	-
Infill Drilling(1)	-	-	-	-	-	-
Improved Recovery(1)	-	-	-	-	-	-
Technical Revisions	-	-	-	(1,583)	1,944	361
Acquisitions	-	-	-	-	-	-
Dispositions	-	-	-	(195)	(406)	(601)
Economic Factors	-	-	-	(35)	(96)	(130)
Production	-	-	-	(398)	-	(398)
December31,2020	-	-	-	725	4,753	5,478

FACTORS	------------------------------------------------------- Shale Gas	------------------------------------------------------- Shale Gas	------------------------------------------------------
	Proved (MMcf)	Probable (MMcf)	Proved Plus Probable (MMcf)
December 31, 2019	35	1,296	1,331
Discoveries	-	-	-
Extensions(1)	108	1,025	1,133
Infill Drilling(1)	-	-	-

6

Improved Recovery(1)	-	-	-
Technical Revisions	80	395	475
Acquisitions	-	-	-
Dispositions	-	-	-
Economic Factors	-	-	-
Production	-	-	-
December 31, 2020	223	2,716	2,940

Notes:

(1) The above change categories correspond to standards set out in the Canadian Oil and Gas Evaluation Handbook. For reporting under NI 51-101, reserves additions under Infill Drilling, Improved Recovery and Extensions should be combined and reported as "Extensions and Improved Recovery".

Undeveloped Reserves

Undeveloped reserves are attributed by GLJ in accordance with standards and procedures contained in the COGE Handbook. Proved undeveloped reserves are generally those reserves related to infill wells that have not yet been drilled or wells further away from gathering systems requiring relatively high capital to bring on production. Probable undeveloped reserves are generally those reserves tested or indicated by analogy to be productive, infill drilling locations and lands contiguous to production. This also includes the probable undeveloped wedge from the proved undeveloped locations.

The Corporation currently plans to pursue the development of its proved and probable undeveloped reserves within the next two years through ordinary course capital expenditures. In some cases, it may take longer than two years to develop these reserves. There are a number of factors that could result in delayed or cancelled development, including the following: (i) existence of higher priority expenditures; (ii) changing economic conditions (due to pricing, operating and capital expenditure fluctuations); (iii) changing technical conditions (including production anomalies, such as water breakthrough or accelerated depletion); (iv) multi-zone developments (for instance, a prospective formation completion may be delayed until the initial completion is no longer economic); (v) a larger development program may need to be spread out over several years to optimize capital allocation and facility utilization; and (vi) surface access issues (including those relating to land owners, weather conditions and regulatory approvals).

Proved undeveloped reserves have been assigned in areas where the reserves can be estimated with a high degree of certainty. In most instances, proved undeveloped reserves will be assigned on lands immediately offsetting existing producing wells within the same accumulation or pool.

Probable undeveloped reserves have been assigned in areas where the reserves can be estimated with less certainty. It is equally likely that the actual remaining quantities recovered will be greater or less than the proved plus probable reserves. In most instances probable undeveloped reserves have been assigned on lands in the area with existing producing wells but there is some uncertainty as to whether they are directly analogous to the producing accumulation or pool.

Possible undeveloped reserves have been assigned in areas where the reserves can be estimated with less certainty. It is unlikely that the actual quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. In most instances possible undeveloped reserves have been assigned on lands in the area with existing producing wells but there is some uncertainty as to whether they are directly analogous to the producing accumulation or pool.

For more information, see " Risk Factors ".

The following tables set forth the remaining proved undeveloped reserves, the remaining probable undeveloped reserves and the remaining possible undeveloped reserves, each by product type, attributed to the Corporation's assets for the years ended December 31, 2020, 2019 and 2018 and, in the aggregate, before that time based on forecast prices and costs.

See " Other Oil and Gas Information - Principal Properties " and " Report on Reserves Data by Independent Qualified Reserves Evaluator or Auditor – Future Development Costs " for a description of the Corporation's exploration and development plans and expenditures.

7

Proved Undeveloped Reserves

Year 2018 2019 2020	Light and Medium Oil(Mbbl)(1) First Attributed Cumulative at Year End - 766 133 654 - -	Tight Oil(Mbbl) First Attributed Cumulative at Year End 777 777 1,372 2,186 - 3,372
	First Attributed - 133 -	First Attributed 777 1,372 -
Year 2018 2019 2020	Conventional Natural Gas(MMcf) First Attributed Cumulative at Year End 498 1,391 116 710 - -	Shale Gas(MMcf) First Attributed Cumulative at Year End 106 127 19 35 - 223
	First Attributed 498 116 -	First Attributed 106 19 -

Note: (1) Includes NGLs.

Proved undeveloped reserves have been assigned in areas where the reserves can be estimated with a high degree of certainty. In most instances, proved undeveloped reserves will be assigned on lands immediately offsetting existing producing wells within the same accumulation or pool. This is the case for sixteen (5.60 net) proved undeveloped horizontal Vaca Muerta wells at CASE. GLJ has assigned 2.9 MMboe of proved undeveloped reserves in the GLJ Report with $40.8 million of associated undiscounted capital to be spent in the first two years.

Probable Undeveloped Reserves

Year 2018 2019 2020	Light and Medium Oil(Mbbl)(1) First Attributed Cumulative at Year End 184 2,072 33 2,337 - 3,051	Tight Oil(Mbbl) First Attributed Cumulative at Year End 1,520 2,673 5,370 7,236 3,773 12,208
	First Attributed 184 33 -	First Attributed 1,520 5,370 3,773
Year 2018 2019 2020	Conventional Natural Gas(MMcf) First Attributed Cumulative at Year End - 1,250 32 1,997 - 4,278	Shale Gas(MMcf) First Attributed Cumulative at Year End 205 370 913 1,296 661 2,716
	First Attributed - 32 -	First Attributed 205 913 661

Note: (1) Includes NGLs.

Probable undeveloped reserves have been assigned in areas where the reserves can be estimated with less certainty. It is equally likely that the actual remaining quantities will be greater or less that the proved plus probable reserves. In most instances, probable undeveloped reserves will be assigned on lands offsetting existing producing wells within the same accumulation or pool but there is some uncertainty as to whether they are directly analogous . In the GLJ Report, this is the case for thirty four (11.9 net) additional probable undeveloped horizontal Vaca Muerta wells at CASE, twelve additional probable undeveloped horizontal wells and one additional probable undeveloped vertical well at the Puesto Morales Block. GLJ has assigned 13.8 MMboe of probable undeveloped reserves in the GLJ Report with $237.8 million of associated undiscounted capital, of which $50.5 million is forecast to be spent in the first two years.

Significant Factors or Uncertainties

The oil and gas properties of the Corporation have no material extraordinary risks or uncertainties beyond those which are inherent of an oil and gas producing company.

The GLJ report has assumed the successful ten year contract extension for certain leases in Argentina. The National Hydrocarbon

8

Law ("NH Law"), amended in 2014 (see " Industry Conditions – Argentina - Oil and Gas Industry Regulations " ), has provided some clarification to the calculation of the renewal bonus. The GLJ report has included these assumptions for contract renewal terms on the Puesto Morales, Rinconada South and Surubi properties. Notwithstanding this, there can be no certainty to a successful contract renewal for these properties and hence, the Corporation may not realize the future net revenues from these properties beyond their initial expiry date.

General

The process of estimating reserves is complex. It requires significant judgments and decisions based on available geological, geophysical, engineering or economic data. These estimates may change substantially as additional data from ongoing development activities and production performance become available and as economic conditions impacting oil and gas prices and costs change. The reserve estimates contained herein are based on current production forecasts, prices and economic conditions.

As circumstances change and additional data become available, reserve estimates also change. Estimates made are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performance, prices, economic conditions and governmental restrictions.

Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is an inferential science. As a result, the subjective decisions, new geological or production information and a changing environment may impact these estimates. Revisions to reserve estimates can arise from changes in year-end oil and gas prices, and reservoir performance. Such revisions can either be positive or negative.

Abandonment and Reclamation Costs

Abandonment and reclamation costs have been estimated by GLJ in the GLJ Report, attributed to all properties that have been assigned reserves in the GLJ Report and have been taken into account by GLJ in determining reserves that should be attributed to a property and in determining the aggregated future net revenue therefrom. No allowances were made, however, for the abandonment and reclamation of any pipelines. In addition, the Corporation does not recognize abandonment and reclamation obligations on facilities in Argentina where it has determined that there is no legal or constructive obligation to perform such activities.

Centaurus will be liable for its share of ongoing environmental obligations and for the ultimate reclamation of the surface leases, wells, facilities and pipelines held by it upon abandonment. Ongoing environmental obligations are expected to be funded out of cash flow.

Centaurus estimates well abandonment costs on a well-by-well basis using historical costs supplemented by current industry costs and changes in regulatory requirements. Estimated costs of well site abandonment and reclamation were included in the GLJ Report and applied as a deduction in determining future net revenue. The Corporation uses industry historical costs to estimate its abandonment costs when available. The costs are estimated on well-by-well basis. The industry's historical costs are used when available. If representative comparisons are not readily available, an estimate is prepared based on the various regulatory abandonment requirements.

The abandonment and reclamation obligation included in the Corporation's financial statements differs from the amount deducted in the reserves evaluation. The financial statements include abandonment and reclamation obligations for wells that were not assigned year-end reserves, neither of which are included in the GLJ Report.

The Corporation has estimated the net cost to abandon and reclaim all existing wells to be $12.6 million (undiscounted and uninflated) as at December 31, 2020. These costs relate to wells on properties that may or may not have reserves attributed to them. As included in the estimate of future net revenue from proved plus probable reserves, GLJ has used a net cost to abandon and reclaim wells of $23.0 million (undiscounted) as at December 31, 2020. This estimate includes the cost to abandon and reclaim all future undrilled wells that have been attributed reserves but it excludes such costs where reserves have not been assigned.

The Corporation has 192 gross (148 net) wells for which it expects to incur abandonment and reclamation costs.

Future Development Costs

The table below sets out the development costs deducted in the estimation of future net revenue attributable to proved reserves (using forecasted prices and costs only), proved plus probable reserves (using forecast prices and costs only) and proved plus probable plus possible reserves (using forecast prices and costs only).

9

			Future Development Costs (USD M)
Year 2021 2022 2023 2024 Total (Undiscounted) Total (Discounted at 10%)		Total Proved Reserves 7,908 34,053 26,047 927	Total Proved Plus Probable Reserves 25,779 66,642 99,639 62,193	Total Proved Plus Probable Plus Possible Reserves 29,964 66,642 133,066 62,193
		72,148 60,132	309,952 240,415	395,457 301,228

Future development costs are capital expenditures which will be required in the future for Centaurus to convert Proved Undeveloped Reserves, Probable Reserves and Possible Reserves to Proved Producing Reserves.

Centaurus intends to use existing working capital, internally generated cash flow from operations, the Capex Loan and Working Capital Loan, or other debt (if available on favourable terms), new equity issues (if available on favourable terms), farm outs or similar arrangements and strategic financial partnerships to finance its capital expenditure program. The cost of funding could negatively affect disclosed reserves or future net revenue depending on the source and nature of the funding but the impact cannot readily be determined at this time. See " Risk Factors ".

Oil and Natural Gas Wells

The following table sets forth the number and status of oil and natural gas wells in which Centaurus has a WI and which are producing or mechanically capable of producing and the wells which are not producing or mechanically capable of production as of December 31, 2020.

Location Argentina	Oil Wells Gross Net 66 60.35	Oil Wells Gross Net 66 60.35	Natural Gas Wells Gross Net 11 11.0	Natural Gas Wells Gross Net 11 11.0	Non-producing Wells	Non-producing Wells	Non-producing Wells		Total Gross Net 173 162.31
	Gross 66		Gross 11			Gross 96	Net		Gross 173
							90.96
Properties with No Attributed Reserves The following table sets forth Centaurus´ land position as at December 31, 2020. Gross Location Acres Sections Argentina 1,202,424 n/a								Net
		Acres 1,202,424		Sections		Acres 1,110,695
				n/a

The Corporation does not separate out the portion of a block that is undeveloped. As of the date of this report, Centaurus has seven leases in Argentina with attributable reserves totalling 567,057 Gross Acres or 499.551 Net Acres. The remaining work commitments relating to the Corporation's concessions in Argentina are described under " Other Oil and Gas Information - Principal Properties ."

Forward Contracts and Marketing

As of the date hereof, the Corporation has no physical or financial commodity contracts in place, the prices are discussed each month.

Tax Horizon

Argentina

In Argentina, due to the tax reform approved in 2018 the income tax rate in 2018,& 2019 was 30% and in 2020 remained at 30% instead of the expected 25%. This reform also incorporated a tax over dividends of 7% in 2018 and 2019 and remained at 7% in 2020 instead of the expected 13%. Current income tax expense for the year ended December 31, 2020 was nil (2019 – nill). In 2021 a tax reform was approved for fiscal year 2021 with an income tax rate of 25% to 35% and a tax over dividends of 7%.

10

Canada

As at December 31, 2020, the Corporation has, subject to confirmation by income tax authorities, cumulative income tax deductions of approximately CAD $92.0 million (2019 – CAD $92.3 million). Accordingly, the Corporation does not anticipate being taxable in the foreseeable future.

Capital Expenditures

The following table summarizes capital expenditures in Argentina (net of asset retirement costs, and capitalized stock based compensation) related to the Corporation's activities for the year ended December 31, 2020.

the Corporation's activities for the year ended December 31,	2020.
Exploration costs Development costs	Argentina $USD MM 0 7.9
Total	7.9

Exploration and Development Activities

In 2020, the Corporation completed three (1.05 net) horizontal multi-frac wells in the Vaca Muerta Shale Formation at the nonoperated CASE block (operated by PAE).

Production Estimates

The following table sets out the volume of the Corporation's gross working interest production estimated for the year ended December 31, 2021 as evaluated by the Reserve Engineer which is reflected in the estimate of future net revenue disclosed in the tables contained under " Report on reserves data by independent qualified reserves evaluator or auditor ".

	Light and Medium Oil (bopd) Tight Oil (bopd) Conventional Natural Gas (Mcf/d) Shale Natural Gas (Mcf/d) BOE (BOE/d)
Proved Probable Proved Plus Probable Possible Proved Plus Probable Plus Possible	585 651 922 0 1,167 265 290 199 0 492
	851 941 1,120 0 1,659 45 173 53 0 192
	895 1,115 1,174 0 1,850

Production History

The following tables summarize certain information in respect of average sales, product prices received, royalties paid, operating expenses and resulting netback for the periods indicated below.

	Q4	Q3	Q2	Q1
USD	2020	2020	2020	2020
Average Daily Sales Volumes
Light and medium oil – bopd	1,782	2,154	1,953	2,277
Conventional Natural gas – Mcf/d	797	1,028	1,212	1,305
Combined (BOE/d)	1,915	2,325	2,156	2,495

11

Average Price Received
Light and medium oil – $/bbl	37.94	33.63	25.70	43.16
Conventional Natural gas – $/Mcf	1.01	2.44	2.15	2.09
Combined ($/BOE)	35.73	32.23	24.50	40.49
Royalties Paid
Combined ($/BOE)	(6.8)	(5.67)	(3.06)	(6.82)
Operating Costs
Combined ($/BOE)	(21.71)	(18.67)	(23.86)	(23.72)
Netback Received – ($/BOE)	7.22	7.89	(4.42)	9.95

Sales Volume by Field

The following table discloses for each important field, and in total, as a percentage of the Corporation's sales volumes for the financial year ended December 31, 2020 for each product type.

				% (Corporation’s
	Light and Medium	Natural Gas	BOE	consolidated
Field	Crude Oil (bbls/d)	(Mcf/d)	(BOE/D)	production)
Puesto Morales	330	1,006	498	22%
Palmar Largo	397	-	397	18%
Surubi	258	-	258	12%
Coirón Amargo Sur Este	939	-	939	42%
Coirón Amargo Norte	69	80	82	4%
Other minor	48	-	48	2%
Total	2,042	1,086	2223	100%

SCHEDULE "A"

FORM 51-101F2

REPORT ON RESERVES DATA BY

INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

To the board of directors of Centaurus Energy Inc. (the "Company"):

1. We have evaluated the Company’s reserves data as at December 31, 2020. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2020, estimated using forecast prices and costs.

2. The reserves data are the responsibility of the Company’s management. Our responsibility is to express an opinion on the reserves data based on our evaluation.

3. We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the "COGE Handbook") maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter).

4. Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.

5. The following table shows the net present value of future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated for the year ended December 31, 2020, and identifies the respective portions thereof that we have evaluated and reported on to the Company’s board of directors:

==> picture [443 x 112] intentionally omitted <==

1. In our opinion, the reserves data evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.

2. We have no responsibility to update our reports referred to in paragraph 5 for events and circumstances occurring after the effective date of our reports.

3. Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.

Executed as to our report referred to above:

GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada, March 31, 2021

“Originally Signed by”

Patrick A. Olenick, P. Eng. Vice President

SCHEDULE "B"

FORM 51-101 F3 REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION

Report of Management and Directors on Reserves Data and Other Information

Management of Centaurus Energy Inc. (the " Corporation ") is responsible for the preparation and disclosure of information with respect to the Corporation's oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data.

Independent qualified reserves evaluators have evaluated the Corporation's reserves data. The report of the independent qualified reserves evaluators will be filed with the securities regulatory authorities concurrently with this report.

The board of directors of the Corporation has:

• reviewed the Corporation's procedures for providing information to the independent qualified reserves evaluators;

• met with the independent qualified reserves evaluators to determine whether any restrictions affected the ability of the independent qualified reserves evaluators to report without reservation; and

• reviewed the reserves data with management and the independent qualified reserves evaluators.

The Board of directors has reviewed the Corporation's procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The board of directors has approved:

• the content and filing with securities regulatory authorities of Form 51-101F1 containing the reserves data and other oil and gas information;

• the filing of Form 51-102F2 which is the reports of the independent qualified reserves evaluators on the reserves data, contingent resources data or prospective resources data; and

• the content and filing of this report.

Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

Dated at Calgary, Alberta, this 6[th] day of July 2021

(signed) "Steven Balsam" (signed) "Ruben Etcheverrry" Steven Balsam, Ruben Etcheverryt Non-Executive Director Non-Executive Director

(signed) "David D. Tawil" (signed) "Steven Azarbad" David D. Tawil, Steven Azarbad Chief Executive Officer and Director Interim Chief Financial Officer and Director