Parex Resources Inc. — Management Reports 2021

Mar 4, 2021

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MANAGEMENT’S DISCUSSION AND ANALYSIS

The following Management’s Discussion and Analysis (“MD&A”) of the financial condition and results of operations of Parex Resources Inc. (“Parex” or the “Company”) for the three months and year ended December 31, 2020 and 2019 is dated March 3, 2021 and should be read in conjunction with the audited consolidated financial statements for the years ended December 31, 2020 and 2019. The audited consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS” or “GAAP”) as issued by the International Accounting Standards Board.

Additional information related to Parex and factors that could affect the Company’s operations and financial results, including disclosure of production and sales volumes by product type, are included in reports on file with Canadian securities regulatory authorities, including the Company’s Annual Information Form dated March 3, 2021 (the "AIF"), and may be accessed through the SEDAR website at www.sedar.com.

All financial amounts are in United States (US) dollars unless otherwise stated.

Company Profile

Parex is an oil and gas company actively engaged in crude oil exploration, development and production in Colombia. Headquartered in Calgary, Canada, Parex, through its foreign subsidiaries, holds interests in onshore exploration and production blocks. The common shares of the Company trade on the Toronto Stock Exchange (“TSX”) under the symbol PXT.

Abbreviations

Refer to the final page of the MD&A for commonly used abbreviations in the document. Refer to the Advisory on Forward-Looking Statements and Non-GAAP Terms used.

2020 Highlights

• Annual oil and natural gas production in 2020 averaged 46,518 barrels of oil equivalent per day ("boe/d") (97% crude oil), a decrease of 12% over 2019 average production of 52,687 boe/d (98% crude oil)) or 6% on a production per basic share basis as a result of the Company reducing production volumes in the low oil price environment. Refer to "Consolidated Results of Operations" for annual production by product type;

• Recognized net income of $99.3 million ($0.72 per share basic) for the year ended December 31, 2020 compared to net income of $328.0 million ($2.24 per share basic) for the year ended December 31, 2019;

• Generated an operating netback of $20.84/boe (2019 - $37.51/boe) and funds flow provided by operations ("FFO") netback of $17.52/boe (2019 - $29.61/boe) from an average Brent price of $43.30/bbl (2019 - $64.21/bbl);

• Funds flow provided by operations was $297.0 million ($2.15 per share basic), a 48% decrease from the year ended December 31, 2019 of $570.5 million ($3.90 per share basic); FFO was lower in 2020 due to lower sales volumes and lower Brent oil prices compared to 2019;

• Utilized free funds flow of $155.8 million to purchase and cancel 13,851,994 of the Company's common shares for a total cost of $171.5 million at an average price of CAD $16.62 pursuant to the Company's normal course issuer bid program ("NCIB");

• Capital expenditures for the year ended December 31, 2020 were $141.3 million compared to $208.2 million for the year ended December 31, 2019. Capital expenditures were fully funded from FFO;

• Working capital was $320.2 million at December 31, 2020 compared to $344.0 million at December 31, 2019. In addition, the Company has an undrawn syndicated bank credit facility of $200.0 million; and

• Participated in drilling 30 gross (19.45 net) wells in Colombia resulting in 25 oil wells, 2 abandoned wells, 2 wells under test and 1 pressure maintenance well, for a success rate of 93%, compared to 43 gross (26.95 net) wells in the comparative period of 2019.

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1

December 31, 2020

Three Months Ended December 31, 2020 (“fourth quarter" or "Q4”) Highlights

• Fourth quarter oil and natural gas production was 46,642 boe/d (96% crude oil), a decrease of 14% over the fourth quarter of 2019 (8% decrease on a per basic share basis), a 5% increase over the previous quarter ended September 30, 2020 (9% increase on a per basic share basis), and comparable to the 2020 average oil and natural gas production. Refer to "Consolidated Results of Operations" for annual production by product type;

• Recognized net income of $56.2 million ($0.42 per share basic) compared to net income of $27.6 million in the previous quarter ended September 30, 2020 and net income of $87.2 million ($0.61 per share basic) in Q4 2019.

• Generated an operating netback of $24.76/boe (2019 - $36.43/boe) and a funds flow provided by operations ("FFO") netback of $19.06/boe (2019 - $27.89/boe) from an average Brent price of $45.26/bbl (2019 - $62.49/bbl);

• Funds flow provided by operations was $81.6 million ($0.61 per share basic) a 43% decrease compared to $143.3 million ($1.00 per share basic) in Q4 2019; FFO was reduced due to lower sales volumes and lower Brent oil prices;

• Utilized free funds flow of $34.6 million to purchase and cancel 6,606,994 of the Company's common shares for a total cost of $77.2 million (average price of CAD $15.77) pursuant to the Company's NCIB;

• Capital expenditures were $46.9 million in the period compared to $58.3 million in the comparative period of 2019. The fourth quarter capital expenditure program included $41.1 million for drilling and completion;

• Working capital was $320.2 million at December 31, 2020 compared to $370.7 million at September 30, 2020 and $344.0 million at December 31, 2019; and

• Participated in drilling 8 gross (4.85 net) wells in Colombia resulting in 8 oil wells, for a success rate of 100% in Q4 2020 compared to 22 gross (14.60 net) wells in the preceding nine months of 2020 and 15 gross (9.25 net) wells in the fourth quarter of 2019.

Financial Summary

Financial Summary
For the three months ended December 31,	For the year ended December 31,
(Financial figures in$000s exceptper share amounts) 2020 2019	2020 2019 2018
Light Crude and Medium Crude Oil (bbl/d) 6,637 8,346 HeavyCrude Oil(bbl/d) 38,332 44,740	6,021 7,214 4,668 39,197 44,494 39,120
Average daily oil production (bbl/d)(1) 44,969 53,086 Average dailyconventional naturalgasproduction(mcf/d)(1) 10,038 6,810	45,218 51,708 43,788 7,800 5,874 3,720
Average oil and natural gas production (boe/d) 46,642 54,221 Production split (% crude oil) 96 98 Realized sales price ($/boe) 36.95 53.00 Operating netback ($/boe)(2) 24.76 36.43 Oil and natural gas sales 167,264 289,585 Funds flow provided by operations(2)(5) 81,567 143,269 Per share – basic 0.61 1.00 Per share – diluted(2) 0.60 0.98 Net income 56,192 87,218 Per share – basic 0.42 0.61 Per share – diluted 0.42 0.60 Capital expenditures 46,932 58,321 Free funds flow(2) 34,635 84,948 Total assets (end of period) 1,541,081 1,684,581 Working capital surplus (end of period)(3) 320,155 344,031 Bank debt (end of period)(4) — — Weighted average shares outstanding (000s) Basic 133,812 142,967 Diluted 135,184 145,565 Outstandingshares(end ofperiod) (000s) 130,873 143,295	46,518 52,687 44,408 97 98 99 32.55 54.70 58.64 20.84 37.51 41.44 587,520 1,113,622 965,723 297,041 570,480 400,627 2.15 3.90 2.58 2.13 3.83 2.51 99,322 327,994 402,904 0.72 2.24 2.59 0.71 2.20 2.53 141,264 208,196 302,343 155,777 362,284 98,284 1,541,081 1,684,581 1,642,120 320,155 344,031 218,526 — — — 138,356 146,380 155,417 139,619 149,025 159,562 130,873 143,295 155,014

(1) Reference to crude oil or natural gas production in the above table and elsewhere in this MD&A refer to the light and medium crude oil and heavy crude oil and conventional natural gas, respectively, product types as defined in National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities.

(2) Non-GAAP terms. Refer to “Non-GAAP Terms”.

(3) Working capital calculation does not take into consideration the undrawn amount available under the syndicated bank credit facility.

(4) Syndicated bank credit facility borrowing base of $200.0 million as at December 31, 2020, $200.0 million at December 31, 2019.

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2

December 31, 2020

(5) In the second quarter of 2019, Parex changed the way it calculates and presents funds flow from operations. For further details refer to the "Non-GAAP Terms". Comparative periods have also been adjusted for this change. For the year ended December 31, 2018, funds flow provided by operations includes a $137.5 million ($0.88 per share basic) charge for a voluntary tax restructuring.

Guidance

The table below is a summary of Parex’ 2020 actual results and 2021 guidance:

The table below is a summary of Parex’ 2020 actual results and 2021 guidance:
	2020 Actuals	2021 Guidance(5)
Brent crude average ($/bbl)(2)	43	45
Production (average for period) (boe/d)	46,518	47,000-49,000
Total Capex ($ millions)	141	165-185
Funds flow provided by operations (FFO)(1)($ millions)	297	320-340
Free funds flow (FFO less total capex mid-points)(1)($ millions)	156	155
Share buy-back program(3)(5)($ millions)	172	150
Outstanding shares (end of period)(3)(millions)	131	118-120
Production per share growth %	(6)%	14%
Estimated working capital (end of period) ($ millions)	320	335
Bank debt outstanding (end of period) ($ millions)	—	—
Operating netback ($/boe)(1)(2)	21	23
Funds Flow provided by Operations (FFO) netback(1)(2)($/boe)	18	19
Current tax effective rate on FFO(%)(4)	7%	8%

(1) The table above contains Non-GAAP measures. Refer to “Non-GAAP Terms”.

(2) 2021 Guidance assumes Brent/Vasconia crude differential less than $3.75/bbl under $45/bbl Brent pricing scenario.

(3) It is expected free funds flow will be used to fund purchases under the Company's 2021 NCIB and assumes an average share price of CAD $15/share under $45/ bbl Brent pricing scenario.

(4) Effective tax rate is the expected tax rate on funds flow provided by operations.

(5) 2021 Guidance is as released November 2020 and is using USD-CAD exchange rate of 1.31.

Parex' 2020 financial and operational results were below guidance released in November 2019, as a result of the Company voluntarily curtailing production in late first quarter of 2020 in response to the significant decline in world oil prices, reducing the 2020 capital expenditure program by 37%, and the ongoing uncertainty in market conditions resulting from the COVID-19 pandemic. In the third quarter of 2020 the Company began bringing back additional production from previously shut-in or curtailed fields.

The Company expects Q1 2021 average production to be approximately 46,500-47,500 boe/d.

Parex is entering 2021 in a strong operational and financial position. In 2021, the Company expects to purchase the maximum number of shares under its NCIB and fund its planned capital expenditures with funds flow provided by operations, and if appropriate potentially utilizing a portion of cash reserves. Parex does not currently have any commodity price hedging positions active for 2021.

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December 31, 2020

Financial and Operational Results

Consolidated Results of Operations

Parex’ oil and gas operations are conducted in Colombia with head office functions conducted in Canada.

		For the three	months	ended		For the year	For the year	ended
		December 31,				December		31,
		2020		2019		2020		2019
Average daily production
Light Crude and Medium Crude Oil (bbl/d)		6,637		8,346		6,021		7,214
HeavyCrude Oil(bbl/d)		38,332		44,740		39,197		44,494
Crude oil (bbl/d)		44,969		53,086		45,218		51,708
Conventional Natural Gas(mcf/d)		10,038		6,810		7,800		5,874
Total(boe/d)		46,642		54,221		46,518		52,687
Production split (% crude oil production)		96		98		97		98
Average daily sales of oil and natural gas
Produced crude oil (bbl/d)		44,845		54,696		45,022		51,799
Purchased crude oil (bbl/d)		2,688		3,561		3,000		2,991
Produced naturalgas(mcf/d)		10,038		6,810		7,800		5,874
Total(boe/d)		49,206		59,392		49,322		55,769
Operating netback (000s)(1)
Oil and natural gas sales	$	167,264	$	289,585	$	587,520	$	1,113,622
Royalties		**(13,642) **		(36,717)		**(55,655) **		(136,068)
Net revenue		153,622		252,868		531,865		977,554
Production expense		(22,499)		(29,183)		(87,272)		(111,061)
Transportation expense		(16,938)		(20,462)		(59,147)		(88,974)
Purchased oil expense		**(7,536) **		(16,154)		**(28,241) **		(52,791)
Operatingnetback	$	106,649	$	187,069	$	357,205	$	724,728
Operating netback (per boe)(1)
Oil and natural gas sales	$	36.95	$	53.00	$	32.55	$	54.70
Royalties		**(3.19) **		(7.15)		**(3.28) **		(7.06)
Net revenue		33.76		45.85		29.27		47.64
Production expense		(5.26)		(5.68)		(5.15)		(5.76)
Transportation expense		**(3.74) **		(3.74)		**(3.28) **		(4.37)
Operatingnetback	$	24.76	$	36.43	$	20.84	$	37.51

(1) Refer to "Non-GAAP Terms" for a description and details of the operating netback calculation.

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December 31, 2020

4

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Change in Operating Netback by Component
Q4/19 vs. Q4/20
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$40.00 $36.43
$35.00
$30.00
$3.96 $0.42 $— $24.76
$25.00
$20.00
$(16.05)
$15.00
$10.00
$5.00
$0.00
Q4,2019 Netback Revenue Royalties Production CostsTransportation Costs Q4,2020 Netback
$ / boe
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Overall, the Company’s benchmark Brent price decreased by $17.23/bbl, while revenue decreased by $16.05/boe in the fourth quarter of 2020 as compared to the fourth quarter of 2019. The price improvement relative to the Brent crude benchmark decrease is mainly a result of stronger Vasconia pricing (narrowing differential to Brent oil price), partially offset by an increase in wellhead sales as compared to the comparative period. Royalties decreased by $3.96/boe as a result of lower crude prices in the quarter. Production costs decreased by $0.42/ boe mainly as a result of the depreciation of the Colombian peso and the shut-in of higher cost smaller oil fields in Q2 2020.

Overall, the operating netback decreased by $11.67/boe vs a Brent benchmark crude decrease of $17.23/bbl.

Change in Operating Netback by Component Q3/20 vs. Q4/20

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$30.00
$3.07
$24.76
$25.00 $23.10
$(0.22) $(0.26)
$(0.93)
$20.00
$15.00
$10.00
$5.00
$0.00
Q3,2020 Netback Revenue Royalties Production CostsTransportation Costs Q4,2020 Netback
$ / boe
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Overall, the Company’s benchmark Brent price increased by $1.92/bbl, while revenue increased by $3.07/boe in the fourth quarter of 2020 as compared to the third quarter of 2020. The increase in revenue relative to the Brent crude benchmark increase is mainly a result of stronger Vasconia pricing and decreased wellhead sales in the quarter as compared to the comparative period. Royalties increased by $0.22/boe as a result of higher crude oil benchmark prices in the quarter. Production costs increased by $0.26/boe related to the appreciation of the Colombian peso compared to the comparative period. Transportation costs increased by $0.93/boe as a result of decreased wellhead sales in the quarter and the additional direct export oil cargo sales.

Overall, the operating netback increased by $1.66/boe vs a Brent benchmark crude increase of $1.92/bbl.

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December 31, 2020

5

Oil and Natural gas Sales

a) Average Daily Production and Sales Volumes (boe/d)

	For the three	months	For the year	ended
	ended December 31,		December	31,
	2020	2019	2020	2019
Block LLA-34 (Tigana, Jacana and Tua fields)	31,483	40,186	33,917	38,549
Block Cabrestero (Bacano and Akira fields)	6,158	5,739	4,902	6,032
Capachos block (Capachos and Andina fields)	3,654	2,947	3,274	2,440
Block LLA-26 (Rumba field)	1,258	1,468	1,132	1,626
Block LLA-32 (Kananaskis, Calona, Carmentea and Azogue fields)	1,097	1,093	1,142	1,389
Other blocks	1,319	1,653	851	1,672
Total Crude Oil Production	44,969	53,086	45,218	51,708
Naturalgasproduction	1,673	1,135	1,300	979
Total crude oil and naturalgasproduction	46,642	54,221	46,518	52,687
Crude oil inventory (build)draw	**(124) **	1,610	**(196) **	91
Average daily sales ofproduced oil and naturalgas	46,518	55,831	46,322	52,778
Purchased oil	2,688	3,561	3,000	2,991
Sales Volumes	49,206	59,392	49,322	55,769

Oil and natural gas production for the fourth quarter of 2020 averaged 46,642 boe/d, a 14% decrease from the fourth quarter of 2019 and an increase of approximately 5% from the third quarter of 2020 as development drilling was commenced in late Q2 and Q3. Further, in the third quarter of 2020 the Company began bringing back additional production from previously shut-in or curtailed fields.

Oil and natural gas sales in the fourth quarter 2020 were 49,206 boe/d compared to 59,392 boe/d for the fourth quarter of 2019. The decrease in oil sales volumes was a result of the decrease in oil production and purchased oil purchases/sales over the comparative period.

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Production
57,500
98% 98% 98% 98% 98% 97% 97% 96%
55,000
52,500
50,000
47,500
45,000
42,500
40,000
37,500
35,000
32,500
30,000
Q1/2019 Q2/2019 Q3/2019 Q4/2019 Q1/2020 Q2/2020 Q3/2020 Q4/2020
Crude Oil (bbls/d) Natural gas (boe/d) Crude Oil Production as a % of Total Production
bbls/d or boe/d
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December 31, 2020

Production By Area (Three Months ended December 31,2020)

Block Cabrestero: 14%

Block LLA-34: 70%

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Block LLA-26: 3% Block LLA-32: 2% Block Capachos: 8% Other: 3%

b) Crude Oil Reference and Realized Prices

	For the three months	ended	For the year ended	For the year ended
	December 31,		December 31,
	2020	2019	2020	2019
Reference Prices
Brent ($/bbl)	45.26	62.49	43.30	64.21
Vasconia ($/bbl)	42.69	58.50	38.90	60.89
WTI($/bbl)	42.63	56.94	39.44	57.05
Average Realized Prices
Realized salesprice($/boe)	36.95	53.00	32.55	54.70
Realizedprice(differential)to Brent crude($/boe)	**(8.31) **	(9.49)	**(10.75) **	(9.51)

During Q4 2020, the differential between Brent reference pricing and the Company's realized sale price was $8.31/boe. The differential to Brent crude during Q4 2020 decreased by $1.15/boe compared to the third quarter of 2020 where the differential was $9.46/boe (see below).

The table below provides a quarter-by-quarter view of Parex’ historical pricing in Colombia:

Averageprice for theperiod	Q4 2020	Q3 2020	Q2 2020	Q1 2020	Q4 2019
Brent ($/bbl)	45.26	43.34	33.39	51.05	62.49
Vasconia($/bbl)	42.69	40.35	26.70	45.97	58.50
Brent/Vasconia crude (differential) ($/bbl)	(2.57)	(2.99)	(6.69)	(5.08)	(3.99)
Parex quality differential ($/bbl)	(0.15)	(0.35)	(0.44)	(0.18)	(0.72)
Parex wellhead and cargo export sales discount($/bbl)	**(5.59) **	(6.12)	(7.01)	(7.32)	(4.78)
Parex realized salesprice($/boe)	36.95	33.88 5	19.25	38.47 5	53.00
Parex realized price (differential) to Brent crude ($/boe)	(8.31)	(9.46)	(14.14)	(12.58)	(9.49)
Parex transportation expense($/boe)(1)	**(3.74) **	(2.81)	(2.33)	(4.04)	(3.74)
Parexprice differential and transportation expense($/boe)	**(12.05) **	(12.27)	(16.47)	(16.62)	(13.23)

(1) See Transportation section below.

Differences between Parex’ realized price and Vasconia crude price is mainly related to quality adjustments, wellhead sale marketing contracts, and timing of oil sales compared to quarter averages. The differential between Vasconia crude pricing and Brent crude pricing also affects Parex’ realized sales price and is set in liquid global markets and therefore attributed to factors that are beyond the Company’s control. The significant decrease in global crude oil prices beginning in March 2020 widened the Brent/Vasconia differential to as high as $10/bbl in April and May 2020. In the fourth quarter of 2020 the Vasconia differential improved to $2.57/bbl average for Q4 2020 vs $6.69 in Q2 2020. Parex’ Colombian oil production is fully exposed to swings in the Vasconia differential to Brent.

Parex realized price differential to Brent and Vasconia crudes can fluctuate period over period due to, among other factors, the type of sales contract and the accounting treatment for oil sold at the wellhead versus a direct export sales contract.

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December 31, 2020

7

In 2019 the combined price differential and transportation expense had trended downward due to the shrinking of Vasconia crude differential and the depreciation of the Colombian peso, however in the fourth quarter of 2019 this differential began to widen. In the second quarter of 2020, this differential widened further by approximately $2.70/boe compared to the fourth quarter of 2019 and the price differential plus transportation expense increased by $3.24/boe mainly as a result the dramatic decrease in world oil prices beginning in March 2020 as a result of the COVID-19 pandemic. During the third and fourth quarters of 2020, the differential improved dramatically compared to the first two quarters of 2020. This improvement was due to a reduction of global heavy crude differentials which the Company realized through the sale of its Vasconia blended crude.

Parex’ combined transportation costs plus Brent price differential has been trending lower since 2019, except for the period of the COVID-19 pandemic oil price shock in Q1 & Q2 2020. This improvement is primarily the result of an improvement of global heavy crude differentials and Colombia’s location allowing Parex crude oil access to all the major global crude oil buying markets.

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Brent Realized Price Differential & Transportation Expense
$-10.00
$-12.00
$(12.27) $(12.05)
$-14.00 $(12.95) $(13.23)
$(13.79)
$-16.00
$(15.56)
$(16.62) $(16.47)
$-18.00
Q1/2019 Q2/2019 Q3/2019 Q4/2019 Q1/2020 Q2/2020 Q3/2020 Q4/2020
$ / boe
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c) Natural Gas Revenue and Realized Prices

	For the three	months	For the year	ended
	ended December 31,		December	31,
	2020	2019	2020	2019
Natural gas revenue ($000s)	$ 5,392	3,361	$ 17,333	12,562
Realized salesprice($/Mcf)	5.84	5.36	6.07	5.86

Parex natural gas revenues were $5.4 million and $17.3 million for the three months and year ended 2020 compared to $3.4 million and $12.6 million in the same period of 2019. The increase in natural gas sales from the prior periods is related to increased natural gas volumes sold from Block LLA-32 and the Capachos block. At the Capachos block, Parex completed a gas processing facility and a related natural gas in-field flowline.

d) Oil and Natural Gas Revenue

2020 oil and natural gas revenue decreased by $526.1 million or 47% as reconciled in the table below to 2019:

($000s)

($000s)
Oil and natural gas revenue, year ended December 31, 2019	$	1,113,622
Sales volume of produced oil, a decrease of 13% (6,777 bbl/d)		(135,254)
Sales volume of purchased oil, an increase of 0.3% (9 bbl/d)		352
Sales price decrease of 41%		(395,971)
Sales volume andprice change ofproduced naturalgas		4,771
Oil and naturalgas revenue, year ended December 31, 2020	$	587,520

Oil and natural gas revenue decreased year over year mainly due to the decrease in world oil prices and decreased sales volumes of produced oil.

e) Crude Oil Inventory in Transit

($000s)
For theyears ended December 31,		2020		2019
Crude oil in transit	$	1,915	$	653

8

December 31, 2020

At December 31, 2020, the Company had 99.5 mbbls (December 31, 2019 - 27.7 mbbls) of crude oil inventory in transit, which was injected into Colombian pipelines. The inventory was valued based on direct and indirect expenditures (including production costs, transportation costs, depletion expense and royalty expense) at approximately $19/bbl ($24/bbl - 2019) incurred in bringing the crude oil to its existing condition and location.

A reconciliation of quarter to quarter crude oil inventory movements is provided below:

(mbbls)
For theperiods ended	Dec. 31, 2020	Sep. 30,2020	Jun. 30,2020	Mar. 31,2020
Crude oil inventory in transit - beginning of the period	88.0	75.9	250.5	27.7
Oil production	4,118.9	3,940.2	3,615.2	4,830.4
Oil sales	(4,354.7)	(4,179.9)	(4,073.5)	(4,922.8)
Purchased oil	247.3	251.8	283.7	315.2
Crude oil inventoryin transit - end of theperiod	99.5	88.0	75.9	250.5
% ofperiodproduction	2.4	2.2	2.1	5.2

Crude oil inventory build and (draw) from period to period are subject to factors that the Company does not control such as timing of the number of shipments from storage to export. Crude oil inventory as a percentage of quarterly production at December 31, 2020 was 2.4%. Parex expects crude oil inventory in future periods to be in line with normal historic levels of below 5% of period production.

f) Purchased Oil

		For the three	months		For the	year ended	year ended
		ended December 31,			December 31,
		2020	2019		2020		2019
Purchased oil expense($000s)	$	7,536	$16,154	**$ **	28,241	$	52,791

Purchased oil expense for the three months and year ended December 31, 2020 was $7.5 million and $28.2 million as compared to $7.1 million in the preceding quarter and $16.2 million and $52.8 million for the three months and year ended December 31, 2019. Purchased oil expense has decreased as a result of a decrease in oil blending operations and a decrease in purchases of partner crude at certain fields, primarily at the Capachos field. Transportation costs are incurred by the Company to transport purchased oil to sale delivery points.

Royalties

		For the three	months	ended		For the year ended	For the year ended	For the year ended
		December 31,				December 31,
		2020		2019		2020		2019
Royalties ($000s)	$	13,642	$	36,717	$	55,655	$	136,068
Per unit ($/boe)(1)		3.19		7.15		3.28		7.06
Percentage of sales(1)		8.6		13.5		10.1		12.9

(1) Calculated based on Company working interest sales volumes excluding purchased oil volumes sold.

For the three months and year ended December 31, 2020 royalties as a percentage of sales were 8.6% and 10.1%, a decrease from 13.5% and 12.9% in the three months and year ended December 31, 2019. The third quarter of 2020 royalty as a percentage of sales was 8.8%. The decrease in royalties as a percentage of oil sales compared to the prior year is a result of lower benchmark WTI prices which are used in the high price share royalty ("HPR") calculation. Benchmark WTI prices for the three months and year ended December 31, 2020 were $42.63 and $39.44 compared to $40.88 in the third quarter of 2020, and $56.94 and $57.05 for the 2019 comparative periods.

The decrease in royalty expense to $13.6 million and $55.7 million in the three months and year ended December 31, 2020 compared to $36.7 million and $136.1 million for the 2019 comparative prior year periods is a result of lower benchmark WTI prices used in the calculation of royalties and decreased oil production and sales over the prior period. As realized oil prices increase royalties as % of oil sales will also increase to historic levels.

The HPR comes into effect when accumulated production of any production area, inclusive of royalty volumes, exceeds 5 million barrels, and in the event international reference prices exceed pricing determined in the contract. The calculation is described as a “High Price Share” in the Company’s AIF, which may be accessed through the SEDAR website at www.sedar.com.

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9

December 31, 2020

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Royalties
40 12.2% 13.3% 12.5% 13.5% 12.2%
35
10.3%
30 8.8% 8.6%
25
20
15
10
5
0
Q1/2019 Q2/2019 Q3/2019 Q4/2019 Q1/2020 Q2/2020 Q3/2020 Q4/2020
Royalties As a % of Oil and Gas Sales per boe
$ millions
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Production Expense

		For the three	months	ended		For the year ended	For the year ended
		December 31,				December 31,
		2020		2019		2020	2019
Production expense ($000s)	$	22,499	$	29,183	$	87,272 $	111,061
Per unit($/boe)(1)		5.26		5.68		5.15	5.76

(1) Calculated based on Company working interest sales volumes excluding purchased oil volumes sold.

A breakdown of the production expense on a per boe basis between operated and non-operated fields are provided below:

	For the three months	ended	For the year ended
	December 31,		December 31,
	2020	2019	2020	2019
Per unit ($/boe) – based on sales volumes – operated(1)	7.38	8.88	7.34	8.66
Per unit($/boe)– based on sales volumes – non-operated(1)	4.27	4.45	4.33	4.68

(1) Calculated based on Company working interest sales volumes excluding purchased oil volumes sold.

Production expense includes the cost of activities in the field to operate wells and facilities, lift to surface, gather, process, treat and store production.

Production expense for the three months and year ended December 31, 2020 was $5.26/boe and $5.15/boe compared to $5.68/boe and $5.76/boe for the three months and year ended December 31, 2019. Production expense for the third quarter of 2020 was $5.00/boe.

Operated properties production expense in the fourth quarter of 2020 was $7.38/boe compared to $6.09/boe for the third quarter of 2020 and non-operated properties production expense was $4.27/boe for the fourth quarter of 2020 compared to $4.62/boe for the third quarter of 2020.

The decrease in operated production expense for the year ended December 31, 2020 is mainly the result of the depreciation of the Colombian peso, additional production from the Capachos field and the voluntary shut-in of higher operating cost fields compared to the prior period.

The decrease in non-operated production expense for the year ended December 31, 2020 is mainly the result of the depreciation of the Colombian peso comparative to the prior period.

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10

December 31, 2020

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Production Expense
40 $6.15
30 $5.71 $5.51 $5.68 $5.31 $4.98 $5.00 $5.26
20
10
0
Q1/2019 Q2/2019 Q3/2019 Q4/2019 Q1/2020 Q2/2020 Q3/2020 Q4/2020
Production Expenses Production Expenses ($/boe)
Transportation Expense
For the three months ended For the year ended
December 31, December 31,
2020 2019 2020 2019
Transportation expense ($000s) $ 16,938 $ 20,462 $ 59,147 $ 88,974
Per unit ($/boe) 3.74 3.74 3.28 4.37
$ millions
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Transportation expense includes trucking costs incurred to transport production to several offloading stations for sale and in some instances an oil transportation tariff from the in-basin delivery point to the buyer’s facility and national pipeline tariffs for transportation of Parex crude oil to the tide water crude oil export facility.

For the three months ended December 31, 2020, the cost of transportation of $3.74/boe has increased compared to the third quarter of 2020 cost of $2.81/boe and was comparable to the comparative period in 2019. Transportation expense will fluctuate period over period due the mix of sales contracts types in force during the period. The increase from the third quarter of 2020 is mainly due to an increase in oil sale cargo exports where Parex records the full cost of transportation to the point of export.

The combined transportation expense and price differential from Brent, on a per boe basis, has decreased from the fourth quarter of 2019 and third quarter of 2020. See "Crude Oil Reference and Realized Prices".

On a year to date basis transportation expense has decreased to $3.28/boe from $4.37/boe in the comparative period in 2019 mainly as a result of decreased crude cargo exports where Parex records the full cost of transport to the export point and a higher percentage of in-basin wellhead sales where Parex only records the price received at the field.

Transportation Expenses

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30 $5.19
$4.51
25 $4.06 $3.74 $4.04 $3.74
20 $2.81
$2.33
15
10
5
0
Q1/2019 Q2/2019 Q3/2019 Q4/2019 Q1/2020 Q2/2020 Q3/2020 Q4/2020
Transportation Expense Transportation Expenses ($/boe)
$ millions
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11

December 31, 2020

General and Administrative Expense (“G&A”)

		For the three	months	ended		For the year ended	For the year ended	For the year ended
		December 31,				December 31,
($000s)		2020		2019		2020		2019
Gross G&A	$	12,643	$	13,227	$	44,343	$	46,067
G&A recoveries		(544)		(496)		(1,129)		(1,649)
Capitalized G&A		**(2,151) **		(1,820)		**(7,156) **		(10,204)
Net G&A expense	$	9,948	$	10,911	$	36,058	$	34,214
Per unit($/boe)(1)		2.32		2.19		2.12		1.78

(1) Calculated based on Company working interest production volumes.

Net G&A was $9.9 million and $36.1 million for the three months and year ended December 31, 2020 compared to $10.9 million and $34.2 million for the same periods in 2019. Net G&A has increased for the year as a result of decreased capitalized G&A and G&A recoveries as a result of less capital activity compared to the prior year. Gross G&A was $12.6 million and $44.3 million for the three months and year ended December 31, 2020 (three months and year ended December 31, 2019 - $13.2 million and $46.1 million). On a per boe basis net G&A for the year has increased 19% from the comparative year as a result of voluntarily curtailment of production during the year in response to the significant decline in world oil prices and ongoing uncertainty in market conditions resulting from the COVID-19 pandemic.

The Company’s G&A expense is mainly denominated in local currencies of COP and Cdn dollar which as they appreciate/depreciate have an impact on G&A expense. Refer to the "Foreign Exchange Sensitivity Analysis" for further information.

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Net General and Administrative Expenses
15
12 $1.85 $1.90 $2.19 $1.84 $2.27 $2.10 $2.32
9 $1.18
6
3
0
Q1/2019 Q2/2019 Q3/2019 Q4/2019 Q1/2020 Q2/2020 Q3/2020 Q4/2020
Net G&A Expenses Net G&A Expenses ($/boe)
$ millions
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Share-Based Compensation

Share-Based Compensation
		For the three	months	ended		For the year ended
		December 31,				December 31,
($000s)		2020		2019		2020		2019
Equity settled share-based compensation expense	$	1,608	$	1,785	$	4,235	$	7,603
Cash settled share-based compensation expense		8,687		8,202		5,275		20,081
Total net expense	$	10,295	$	9,987	$	9,510	$	27,684

Share-based compensation expense was $9.5 million for the year ended December 31, 2020 compared to $27.7 million for the same period in 2019. The decrease is primarily due to the decrease in the Company's share price and its impact on cash settled share-based compensation expense as explained below.

Equity settled share-based compensation expense was $1.6 million and $4.2 million for the three months and year ended December 31, 2020 compared to $1.8 million and $7.6 million for the same periods in 2019. Equity settled share-based compensation includes the Company's stock option plan and the restricted share unit ("RSU") plan pursuant to which RSUs and performance based RSUs ("PSUs") were awarded. The decrease in the equity settled plan expense from the prior year is mainly related to the decrease in the awards remaining to be amortized under these plans as compared to the prior year.

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12

December 31, 2020

Cash settled share-based compensation relates to the Company's cash settled incentive plans and includes share appreciation rights ("SARs"), cash settled restricted share units ("CRSUs"), cash or share settled restricted share units ("CosRSUs"), cash or share settled performance share units ("CosPSUs") and deferred share units ("DSUs"). The CRSU plan is replacing the current SAR plan for the Colombian employees as granted SAR's vest, and are exercised. There will be no SAR grants going forward. For the three months and year ended December 31, 2020 there was an expense of $8.7 million and $5.3 million related to cash settled incentive plans compared to a $8.2 million expense and expense of $20.1 million for the same periods in 2019. The decrease in expense is attributable to the decrease in Parex share price to Cdn$17.52 at December 31, 2020 from Cdn$24.15 at December 31, 2019, partially offset by the issuance of cash settled compensation. Obligations for payments of cash under the Company's cash settled incentive plans are accrued as expense over the vesting period based on the fair value of the units as described in note 16 - Cash Settled Incentive Plans of the consolidated financial statements for the year ended December 31, 2020. As at December 31, 2020, the total cash settled incentive plans liability accrued is $23.7 million (December 31, 2019 - $27.9 million).

Cash payments to settle cash settled share-based compensation in the three months and year ended December 31, 2020 were $0.5 million and $12.1 million respectively (three months and year ended December 31, 2019 - $0.6 million and $9.2 million).

Depletion, Depreciation and Amortization Expense (“DD&A”)

		For the three	months	ended		For the year ended	For the year ended
		December 31,				December 31,
		2020		2019		2020	2019
DD&A ($000s) total	$	32,554	$	32,636	$	113,758 $	125,899
Per unit($/boe)(1)		7.59		6.54		6.68	6.55

(1) DDA per unit ($/bbl) is calculated using Company working interest production volumes and does not include inventory adjustments.

Fourth quarter 2020 DD&A was $32.6 million ($7.59/boe) compared to $32.6 million ($6.54/boe) for the same period in 2019. For the year ended December 31, 2020 DD&A was $113.8 million ($6.68/boe) as compared to $125.9 million ($6.55/boe) for the prior year.

For the fourth quarter of 2020, future development costs of $422.7 million (three months ended December 31, 2019 - $453.1 million) were included in the depletion calculation. Fourth quarter 2020 DD&A of $7.59/boe increased from the comparative period of $6.54/boe due to a small decrease in proved and probable reserves and oil and gas production from the prior comparative period.

DD&A

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$7.59
35 $6.39 $6.59 $6.65 $6.54 $6.00 $6.79 $6.45
30
25
20
15
10
5
0
Q1/2019 Q2/2019 Q3/2019 Q4/2019 Q1/2020 Q2/2020 Q3/2020 Q4/2020
Depletion, Depreciation and Amortization Expense DD&A per boe, before impairment (recovery) ($/boe)
$ millions
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Foreign Exchange

		For the three	months	ended		For the year ended	For the year ended
		December 31,				December 31,
($000s)		2020		2019		2020		2019
Foreign exchange (gain) loss	$	10,222	$	5,733	$	(102)	$	10,657
Foreign currencyrisk management contracts loss(gain)		—		(245)		511	—	(3,733)
Total foreign exchange loss	$	10,222	$	5,488	$	409	$	6,924
Average foreign exchange rates
USD$/CAD$		1.30		1.32		1.34		1.33
USD$/Colombianpeso		3,662		3,404		3,693		3,281

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13

December 31, 2020

The Company’s main exposure to foreign currency risk relates to the pricing of foreign currency denominated in Canadian dollars and Colombian pesos ("COP"), as the Company’s functional currency is the US dollar. The Company has exposure in Colombia and Canada on costs, such as capital expenditures, local wages, royalties and income taxes, all of which may be denominated in local currencies. The main drivers of foreign exchange loss and gain recorded on the consolidated statements of comprehensive income is the COP denominated tax withholdings receivable and income tax payable balances in Colombia. The timing of payment settlements, accruals and their adjustments have impacts on foreign exchange gains/losses.

For the three months and year ended December 31, 2020, a total foreign exchange loss of $10.2 million and $0.4 million was recorded compared to a loss of $5.5 million and $6.9 million in the respective prior year periods. Unrealized foreign exchange gains and losses may be reversed in the future as a result of fluctuations in exchange rates and are recorded in the Company’s consolidated statement of comprehensive income.

The Company reviews its exposure to foreign currency variations on an ongoing basis and maintains cash deposits primarily in USD denominated deposits in Canada, Barbados, Bermuda and Colombia.

Foreign Exchange Sensitivity Analysis

Cost component Estimated percent of cost denominated in local currency	$/boe Impact of change in local currency/ $USD exchange rate
	10% appreciation of local currency 10% depreciation of local currency
Production expense 80 % $ 0.42 $ (0.42) Transportation expense 80 % $ 0.30 $ (0.30) G&A expense 100 % $ 0.23$ (0.23)

The table above displays the estimated per boe impact of a change in Parex' local currencies and the effect on Parex' key cost components. The component impact in $/boe terms uses Q4 2020 per boe costs. This analysis ignores all other factors impacting cost structure including efficiencies, cost reduction strategies, etc.

Net Finance Expense

		For the three	months	ended		For the year ended	For the year ended
		December 31,				December 31,
		2020		2019		2020		2019
Bank charges and credit facility fees	$	514	$	784	$	2,630	$	3,647
Accretion on decommissioning and environmental liabilities		925		1,269		4,125		4,592
Interest and other income		(250)		(1,062)		(2,129)		(7,382)
Right of use asset interest		4		22		54		99
Loss (gain) on settlement of decommissioning liabilities		442		(1,301)		803		359
Loss on disposition of tangible assets		1		3		1,345		235
Expected credit loss provision (recovery)		(428)		—		1,006		—
Other		**(174) **		1,983		**(821) **		2,026
Net finance expense	$	1,034	$	1,698	$	7,013	$	3,576
		For the three	months	ended		For the year ended
		December 31,				December 31,
		2020		2019		2020		2019
Non-cash finance expense	$	766	$	1,954	$	6,458	$	7,212
Cash finance expense(income)		268		(256)		555		(3,636)
Net finance expense	$	1,034	$	1,698	$	7,013	$	3,576

Bank taxes and credit facility fees relate to bank taxes paid in Colombia and the standby fees related to the undrawn credit facility. The noncash components of net finance expense include the accretion on decommissioning and environmental liabilities, loss (gain) on settlement of decommissioning liabilities, loss on disposition of tangible assets, other and the expected credit loss provision (recovery) which has increased due to the COVID-19 pandemic and it's impact on credit markets and ratings.

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14

December 31, 2020

Risk Management

Management of cash flow variability is an integral component of Parex’ business strategy. Changing business conditions are monitored regularly and, where material, reviewed with the Board of Directors to establish risk management guidelines to be used by management. The risk exposure inherent in movements in the price of crude oil, fluctuations in the US/COP exchange rate and interest rate movements are all proactively reviewed by Parex and as considered appropriate may be managed through the use of derivatives. The Company considers these derivative contracts to be an effective means to manage and forecast cash flow.

Parex has elected not to apply IFRS prescribed “hedge accounting” rules and, accordingly, pursuant to IFRS the fair value of the financial contracts is recorded at each period-end. The fair value may change substantially from period to period depending on commodity and foreign exchange forward strip prices for the financial contracts outstanding at the balance sheet date. The change in fair value from period-end to period-end is reflected in the earnings for that period. As a result, earnings may fluctuate considerably based on the period-ending commodity and foreign exchange forward strip prices.

a) Risk Management Contracts – Brent Crude

At December 31, 2020 the Company had no crude oil risk management contracts in place and still has no crude oil risk management obligations at the time of writing this MD&A. Parex has no outstanding draw on its credit facility or significant commitments due in the next 12 months and as such it is considered appropriate not to have any commodity derivative contracts in place at this time and thereby avoid the costs associated with these types of contracts.

The table below summarizes the loss on the commodity risk management contracts that were in place during the three months and years ended December 31, 2020 and 2019:

		For the three	months	ended		For the year ended
		December 31,				December 31,
($000s)		2020		2019		2020	2019
Realized loss on commodityrisk management contracts	$	—	$	—	$	3,940	—
Total	$	—	$	—	$	3,940 $	—

The Company has no commodity risk management contracts in place for 2021 and so is fully exposed to fluctuations in oil prices.

b) Risk Management Contracts – Foreign Exchange

The Company is exposed to foreign currency risk as various portions of its cash balances are held in Colombian pesos (COP) and Canadian dollars (Cdn$) while its committed capital expenditures are expected to be primarily denominated in US dollars.

At December 31, 2020 the Company had no foreign currency risk management contracts in place.

The table below summarizes the loss (gain) on the foreign currency risk management contracts that were in place during the three months and years ended December 31, 2020 and 2019:

		For the three	months	ended		For the year ended	For the year ended
		December 31,				December 31,
($000s)		2020		2019		2020		2019
Premiums paid on foreign currency risk management contracts	$	—	$	178	$	—	$	389
Unrealized (gain) on foreign currency risk management contracts		—		(213)		—		(8,591)
Realized loss(gain)on foreign currencyrisk management contracts		—		(210)		511		4,469
Total	$	—	$	(245)	$	511	$	(3,733)

The Company recorded a realized $0.5 million loss on these contracts in the year ended December 31, 2020 which is recorded in the financial statement line item “Foreign exchange (gain) loss" in the consolidated statements of comprehensive income. The Company recorded an $8.6 million unrealized gain and $4.9 million loss realized on these contracts in the year ended December 31, 2019 which is recorded in the financial statement line item “Foreign exchange (gain) loss".

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15

December 31, 2020

Income Tax

The components of tax expense (recovery) for the three months and year ended December 31, 2020 and 2019 were as follows:

		For the three	months	ended		For the year ended	For the year ended	For the year ended
		December 31,				December 31,
($000s)		2020		2019		2020		2019
Current tax expense	$	10,885	$	32,763	$	20,674	$	120,163
Deferred tax expense(recovery)		**(30,647) **		(10,855)		53,355		55,507
Total tax expense(recovery)	$	**(19,762) **	$	21,908	$	74,029	$	175,670

Current tax expense in the fourth quarter of 2020 was $10.9 million as compared to $32.8 million in the comparative three month period. In the current quarter tax expense as a percentage of consolidated cash flows before tax was 11.8%. For the full year 2020 the Company recorded $20.7 million of current tax expense as compared to $120.2 million in 2019. This decrease is mainly a result of a decrease in cash flows from the prior period primarily as a result of the reduction in Brent oil prices in 2020.

Deferred tax in the fourth quarter of 2020 was a recovery of $30.6 million and an expense of $53.4 million for the year ended December 31, 2020 ($10.9 million recovery and $55.5 million expense for the three months and year ended December 31, 2019). The deferred tax recovery in the quarter is a result of the appreciation of the Colombian peso at the period end date compared to the prior year and its effect on the Colombian tax basis.

Capital Expenditures and Acquisitions

Capital Expenditures and Acquisitions
($000s)		Colombia				Canada				Total
For theyear ended December 31,		2020		2019		2020		2019		2020		2019
Acquisition of unproved properties	$	1,474	$	1,476	$	—	$	—	$	1,474	$	1,476
Geological and geophysical		1,466		12,366		—		—		1,466		12,366
Drilling and completion		125,096		175,502		—		—		125,096		175,502
Well equipment and facilities		12,616		18,600		—		—		12,616		18,600
Other		467		130		145		122		612		252
Total capital expenditures and acquisitions	**$ **	141,119	$	208,074	$	145	$	122	**$ **	141,264	$	208,196
($000s)		Colombia				Canada				Total
For the three months ended December 31,		2020		2019		2020		2019		2020		2019
Acquisition of unproved properties	$	986	$	52	$	—	$	—	$	986	$	52
Geological and geophysical		542		4,349		—		—		542		4,349
Drilling and completion		41,075		52,676		—		—		41,075		52,676
Well equipment and facilities		3,991		1,126		—		—		3,991		1,126
Other		337		75		1		43		338		118
Total capital expenditures and acquisitions	**$ **	46,931	$	58,278	$	1	$	43	**$ **	46,932	$	58,321

Capital Expenditures Summary

During the year ended December 31, 2020 the Company incurred $141.3 million of capital expenditures compared to $208.2 million in the same period of 2019. During 2020 the Company drilled 30 gross (19.45 net) wells, compared to 43 gross (26.95 net) wells in 2019.

During the year ended December 31, 2020 capital expenditures of $141.3 million were self-funded from funds flow from operations of $297.0 million. The Company has maintained its ability to fund growth from cash flow since 2012, excluding the cost of a corporate acquisition completed in 2014.

In the fourth quarter of 2020 the Company drilled 8 gross (4.85 net) wells in Colombia compared to 15 gross (9.25 net) wells in the comparative period. Drilling and completion costs during the fourth quarter of 2020 totaled $41.1 million mainly related to drilling and completion costs in Colombia at Blocks LLA-34 and Fortuna.

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16

December 31, 2020

Non-cash Impairment Charges

Non-cash Impairment Charges
		For the three	months	ended		For the year ended
		December 31,				December 31,
($000s)		2020		2019		2020		2019
Impairment of E&E assets	$	6,166	$	17,223	$	6,166	$	22,767
Impairment of PP&E related to Boranda CGU		—		—		7,000		—
Total non-cash impairment charges before deferred income tax
recoveries	$	6,166	$	17,223	$	13,166	$	22,767

2020 Impairments

The impairment of E&E assets during the three months and year ended December 31, 2020 of $6.2 million is primarily associated with the costs in blocks in the process to relinquish that will not be recovered. The net book value of costs on these block has been impaired to $nil.

As a result of the COVID-19 pandemic and the significant decrease in forecast global crude oil prices compared to those at December 31, 2019, an indication of impairment was identified for all CGUs at March 31, 2020 and impairment tests were performed. The Company determined that the carrying amount of the Boranda CGU in the Magdalena Basin exceeded its recoverable amount and an impairment of $7.0 million was recorded in the consolidated statements of comprehensive income (loss) for the three month period ended March 31, 2020. All other CGU's were found to have recoverable amounts greater than carrying amounts. The recoverable amount for this testing was determined using fair value less cost of disposal. Future cash flows for the CGU's declined due to lower crude oil prices.

The fair value as determined for the Company's producing properties was consistent with the Company's independent qualified reserve evaluators reserve estimate at December 31, 2019, updated for forecast oil prices at March 31, 2020 and adjusting for first quarter production and future development capital expenditures. There are no E&E assets associated with this CGU. Future cash flows were discounted using a rate of 11%. As at March 31, 2020, the recoverable amount of the CGU was estimated to be $16.5 million. The impairment of $7.0 million was due to the lower crude oil price forecast at March 31, 2020 assumed in the fair value calculation compared to the prior year. A 1% change to the assumed discount rate or a 5% change in forward price estimates over the life of the reserves would have an immaterial impact on the impairment.

The future oil prices used in the model are based on a forecast of crude oil prices by Parex' independent reserve evaluators.

Prices used at March 31, 2020 are as follows:

	2020	2021	2022	2023	2024	Thereafter
Brent($US/bbl)	38.64	45.50	52.50	57.50	62.50	2% increaseperyear

At December 31, 2020 Parex tested its CGU's for PP&E impairment where it was determined that the recoverable amount of the CGU's exceeded their carrying amounts, and therefore the Company's CGU's were not impaired. The recoverable amount was determined using estimated fair value less costs of disposal. Future cash flows were discounted using an after tax discount rate of 12% with the following prices being used by Parex’ independent reserve evaluator at December 31, 2020:

	2021	2022	2023	2024	2025	Thereafter
Brent($US/bbl)	50.75	55.00	58.50	61.79	62.95	2% increaseperyear

At December 31, 2020 and 2019 there were no indicators of impairment noted for PP&E, or indicators requiring a reversal of previously recorded impairments.

2019 Impairments

The impairment of E&E assets during the three months and year ended December 31, 2019 of $17.2 million and $22.8 million was primarily associated with the LLA-10 block exploration costs that would not be recovered as the Company had plans to relinquish the block, post drilling of the Tautaco dry hole. 2019 impairments include Morpho block costs that would not be recovered as the Company had relinquished the LLA-10 block. The net book value of costs on this block has been impaired to $nil.

At December 31, 2019 Parex tested its CGU's for PP&E impairment where it was determined that the recoverable amount of the CGU's exceeded their carrying amounts, and therefore the Company's CGU's were not impaired. The recoverable amount was determined using estimated fair value less costs of disposal. Future cash flows were discounted using an after tax rate of 11% with the following prices being used by Parex’ independent reserve evaluator at December 31, 2019:

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17

December 31, 2020

	2020	2021	2022	2023	2024	Thereafter
Brent($US/bbl)	67.00	68.00	71.00	73.00	75.00	2% increaseperyear

For further information regarding the impairment charges for the years ended December 31, 2020 and 2019, refer to note 7 - Exploration and Evaluation Assets and note 8 - Property, Plant and Equipment in the audited consolidated financial statements.

Impairment Test of Goodwill

The Company performed its annual test for goodwill impairment at the balance sheet date in accordance with its policy described in note 3 - Summary of Significant Accounting Policies of the audited consolidated financial statements for the years ended December 31, 2020 and 2019. The Company has allocated goodwill to the Colombia operating segment. The estimated fair value less costs of disposal of the Colombia operating segment exceeded the carrying value. As a result, no goodwill impairment was recorded. For additional information refer to note 10 - Goodwill in the audited consolidated financial statements.

Summary of Quarterly Results

Summary of Quarterly Results
Three months ended($000s) (exceptper share amounts)	Dec. 31, 2020		Sep. 30,2020		Jun. 30,2020			Mar. 31,2020
Average daily oil and natural gas production (boe/d)		46,642		44,305		40,858		54,295
Realized sales price ($/boe)		36.95		33.88		19.25		38.47
Financial
Oil and natural gas sales	$	167,264	$	146,231	$	80,407	$	193,618
Funds flow provided by operations(1)	$	81,567	$	79,384	$	38,777	$	97,313
Per share – basic		0.61		0.57		0.28		0.69
Per share – diluted(1)		0.60		0.57		0.27		0.68
Net income (loss)	$	56,192	$	27,619	$	19,290	$	(3,779)
Per share – basic		0.42		0.20		0.14		(0.03)
Per share – diluted		0.42		0.20		0.14		(0.03)
Capital Expenditures, excluding corporate acquisitions	$	46,932	$	17,756	$	5,310	$	71,266
Total assets (end of period)	$	1,541,081	$	1,548,484	$	1,533,377	$	1,610,341
Workingcapital surplus(end ofperiod)(2)	$	320,155	$	370,722	$	339,310	$	330,356

(1) Non-GAAP term. See “Non-GAAP Terms” below.

(2) Working capital does not include the undrawn amount available on the credit facility.

Three months ended($000s) (exceptper share amounts)		Dec. 31,2019		Sep. 30,2019		Jun. 30,2019		Mar. 31,2019
Average daily oil and natural gas production (boe/d)		54,221		53,045		52,252		51,208
Realized sales price ($/boe)		53.00		53.59		59.92		52.33
Financial
Oil and natural gas sales	$	289,585	$	275,693	$	301,750	$	246,594
Funds flow provided by operations(1)	$	143,269	$	142,733	$	150,973	$	133,505
Per share – basic		1.00		0.99		1.03		0.88
Per share – diluted(1)		0.98		0.97		1.00		0.86
Net income	$	87,218	$	57,257	$	101,505	$	82,014
Per share – basic		0.61		0.40		0.69		0.54
Per share – diluted		0.60		0.39		0.67		0.53
Capital Expenditures, excluding corporate acquisitions	$	58,321	$	48,600	$	48,742	$	52,533
Total assets (end of period)	$	1,684,581	$	1,593,802	$	1,574,528	$	1,657,956
Workingcapital surplus(end ofperiod)(2)	$	344,031	$	279,949	$	240,087	$	207,414

(1) Non-GAAP term. See “Non-GAAP Terms” below. In the second quarter of 2019, Parex changed the way it calculates and presents funds flow from operations. Comparative periods have also been adjusted for this change.

(2) Working capital does not include the undrawn amount available on the credit facility.

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18

December 31, 2020

Factors that Caused Variations Quarter Over Quarter

During the fourth quarter of 2020, production of 46,642 boe/d was in excess of production compared to the previous quarter ended September 30, 2020. Revenue and funds flow provided by operations were higher than the previous quarter due to an increase in volumes sold and realized prices. Working capital decreased to $320.2 million from $370.7 million at September 30, 2020 primarily due to buying back 6.6 million shares pursuant to the Company's NCIB.

During the third quarter of 2020, production of 44,305 boe/d (consisting of 4,626 bbls/d light crude oil and medium crude oil, 38,309 bbls/d of heavy crude oil and 8,220 mcf/d of conventional natural gas) was in excess of production for the previous quarter ended June 30, 2020. Revenue and funds flow provided by operations were higher than the previous quarter due to an increase in realized prices and volumes sold. Working capital increased to $370.7 million from $339.3 million at June 30, 2020.

During the second quarter of 2020, production of 40,858 boe/d (consisting of 4,186 bbls/d light crude oil and medium crude oil, 35,478 bbls/d of heavy crude oil and 7,164 mcf/d of conventional natural gas) was lower than production for the previous quarter ended March 31, 2020. Revenue and funds flow provided by operations were lower than the previous quarter mainly due to decrease in realized prices and volumes sold. Working capital increased to $339.3 million from $330.4 million at March 31, 2020.

During the first quarter of 2020, production of 54,295 boe/d (consisting of 8,380 bbls/d light crude oil and medium crude oil, 44,657 bbls/d of heavy crude oil and 7,548 mcf/d of conventional natural gas) was in excess of production for the previous quarter ended December 31, 2019. Revenue and funds flow provided by operations were lower than the previous quarter mainly due to a decrease in realized prices and volumes sold. Working capital decreased to $330.4 million from $344.0 million at December 31, 2019.

During the fourth quarter of 2019, production of 54,221 boe/d (consisting of 8,346 bbls/d light crude oil and medium crude oil, 44,740 bbls/d of heavy crude oil and 6,810 mcf/d of conventional natural gas) was in excess of production from the previous quarter ended September 30, 2019. Revenue and funds flow provided by operations were higher than the previous quarter due to an increase in volumes sold, partially offset by a decrease in realized prices. Working capital increased to $344.0 million from $279.9 million at September 30, 2018.

Please refer to “Financial and Operating Results” for detailed discussions on variations during the comparative quarters and to Parex’ previously issued annual and interim MD&As for further information regarding changes in prior quarters.

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19

December 31, 2020

Fourth Quarter Results

Consolidated Statements of Comprehensive Income for the three months ended December 31, 2020 and 2019:

($000s) For the three month period ended December 31,		2020		2019
Oil and natural gas sales	$	167,264	$	289,585
Royalties		**(13,642) **		(36,717)
Revenue		153,622		252,868
Expenses
Production		22,499		29,183
Transportation		16,938		20,462
Purchased oil		7,536		16,154
General and administrative		9,948		10,911
Impairment of exploration and evaluation assets		6,166		17,223
Equity settled share-based compensation expense		1,608		1,785
Cash settled share-based compensation expense		8,687		8,202
Depletion, depreciation and amortization		32,554		32,636
Foreignexchangeloss		10,222		5,488
		116,158		142,044
Finance (income)		(250)		(1,062)
Finance expense		1,284		2,760
Net finance expense		1,034		1,698
Income before income taxes		36,430		109,126
Income tax (recovery) expense
Current tax expense		10,885		32,763
Deferred tax(recovery)		**(30,647) **		(10,855)
		(19,762)		21,908
Net income and comprehensive income for the period	$	56,192	$	87,218

Liquidity and Capital Resources

As at December 31, 2020 the Company had a working capital surplus of $320.2 million, excluding amounts available under the credit facility, as compared to working capital surplus of $344.0 million at December 31, 2019. Bank debt was $nil at December 31, 2020 and December 31, 2019. The credit facility has a current borrowing base of $200.0 million and is subject to a borrowing base redetermination to be completed by the end of May 2021. At December 31, 2020 Parex held $330.6 million of cash, compared to $353.3 million at September 30, 2020 and $396.8 million at December 31, 2019. The Company’s cash balances reside primarily in current accounts with chartered financial institutions, the majority of which are held on account in Canada, Barbados, Bermuda and Colombia in USD.

Parex' senior secured credit facility (“credit facility”) with a syndicate of banks has a current borrowing base of $200.0 million. Key covenants include a rolling four quarters total funded debt to adjusted EBITDA test of 3:50:1, and other standard business operating covenants. Given there is $nil balance drawn on the facility as at December 31, 2020, the Company is in compliance with all covenants. The next annual review is scheduled to occur at the end of May 2021. As the Company currently has $nil bank debt and no plans in 2021 to utilize the credit facility, the next re-determination is not expected to impact the Company’s current or future operations or reduce the 2021 outlook.

On December 19, 2019 the Toronto Stock Exchange ("TSX") approved the Company's NCIB application to purchase up to 13,986,994 of the Company's common shares for cancellation. The NCIB commended on December 23, 2019 and the maximum number of shares were repurchased by December 17, 2020 at an average price of Cdn$16.69.

On December 21, 2020, the Toronto Stock Exchange ("TSX") approved the Company's NCIB application to purchase up to 12,868,562 of the Company's common shares for cancellation. The NCIB commenced on December 23, 2020 and will terminate on December 22, 2021 or such earlier time as the NCIB is completed or terminated by Parex. The Company also entered into an automatic share purchase plan with a broker to facilitate repurchases of Common Shares pursuant to the Company's NCIB. Under the Company’s automatic share purchase plan, the Company’s broker may repurchase Common Shares under the NCIB during the Company’s self-imposed blackout periods.

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20

December 31, 2020

Refer to note 24 - Commitments and Contingencies of the audited financial statements for the year ended December 31, 2020 for a description of the performance guarantee facility with Export Development Canada as well as the unsecured letters of credit.

Outstanding Share Data

Parex is authorized to issue an unlimited number of voting common shares without nominal or par value. As at December 31, 2020 the Company had 130,872,676 common shares outstanding compared to 143,295,054 at December 31, 2019, a decrease of 9%. At March 3, 2021 the common shares outstanding has been reduced to 129,430,548 due to the NCIB.

The Company has a stock option plan and RSU (which includes PSUs) plan. The plans provide for the issuance of stock options, RSUs and PSUs to the Company’s officers, executive and certain employees to acquire common shares. In 2019, Parex created a new cash or share settled RSU and PSU plan. Under this new plan any employee who chooses share settlement will receive common shares of the Company purchased on the open market, hence there will be no new issuance of common shares from treasury under this new plan. Going forward, it is expected that only the grants under the Company's stock option plan and the exercise of previously issued RSUs and PSUs will result in common shares issued from treasury.

As at March 3, 2021 Parex has the following securities outstanding:

As at March 3, 2021 Parex has the following securities outstanding:
	Number	%
Common shares	129,430,548	98
Stock options	1,630,840	1
Restricted andperformance share units	717,178	1
	131,778,566	100

As of the date of this MD&A, total stock options, RSUs and PSUs outstanding represent approximately 2% of the total issued and outstanding common shares.

Contractual Obligations, Commitments and Guarantees

In the normal course of business, Parex has entered into arrangements and incurred obligations that will affect the Company’s future operations and liquidity. These commitments primarily relate to exploration work commitments including seismic and drilling activities. The Company has discretion regarding the timing of capital spending for exploration work commitments, provided that the work is completed by the end of the exploration periods specified in the contracts or the Company can negotiate extensions of the exploration periods. The Company’s exploration commitments are described in the Company’s AIF under “Description of Business - Principal Properties”. These obligations and commitments are considered in assessing cash requirements in the discussion of future liquidity.

In Colombia, the Company has provided guarantees to the ANH which on December 31, 2020 were $46.4 million (December 31, 2019 - $47.9 million) to support the exploration work commitments on its blocks. The guarantees have been provided in the form of letters of credit for varying terms. Export Development Canada has provided performance security guarantees under the Company’s $150.0 million (December 31, 2019 - $150.0 million) performance guarantee facility to support approximately $21.9 million (December 31, 2019 - $25.4 million) of the letters of credit issued on behalf of Parex. The letters of credit issued to the ANH are reduced from time to time to reflect the work performed on the various blocks. At December 31, 2020, there are an additional $24.5 million (December 31, 2019 - $22.5 million) letters of credit that are provided by a Latin American bank on an unsecured basis.

The following table summarizes the Company’s estimated undiscounted commitments as at December 31, 2020:

($000s)		Total		<1year	1 – 3years	1 – 3years	3 – 5years	3 – 5years		>5years
Exploration	$	169,408	$	37,507	$	42,810	$	89,091	$	—
Office and accommodations(1)		7,512		2,750		3,242		1,520		—
Decommissioningand Environmental Obligations		80,962		7,054		—		—		73,908
Total	**$ **	257,882	$	47,311	$	46,052	$	90,611	$	73,908

(1) Includes minimum lease payment obligations associated with leases for office space and accommodations.

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21

December 31, 2020

Decommissioning and Environmental Liabilities

Decommissioning and Environmental Liabilities
		Decommissioning		Environmental		Total
Balance,December 31,2018	$	42,052	$	15,549	$	57,601
Additions		10,524		1,355		11,879
Settlements of obligations during the year		(10,536)		(1,229)		(11,765)
Loss on settlement of obligations		359		—		359
Accretion expense		3,166		1,426		4,592
Change in estimate - inflation and discount rates		1,455		170		1,625
Change in estimate - costs		(10,253)		(2,532)		(12,785)
Foreign exchange loss(gain)		477		(48)		429
Balance,December 31,2019	$	37,244	$	14,691	$	51,935
Additions		2,554		480		3,034
Settlements of obligations during the year		(3,560)		(1,070)		(4,630)
Loss on settlement of obligations		803		—		803
Accretion expense		2,286		1,839		4,125
Change in estimate - inflation and discount rates		360		(2,062)		(1,702)
Change in estimate - costs		(441)		(286)		(727)
Foreign exchange(gain)		(1,036)		(691)		(1,727)
Balance, December 31, 2020		38,210		12,901		51,111
Current obligation		(3,629)		(3,425)		(7,054)
Long-term obligation	$	34,581	$	9,476	$	44,057

The total environmental, decommissioning and restoration obligations were determined by management based on the estimated costs to settle environmental impact obligations incurred and to reclaim and abandon the wells and well sites based on contractual requirements. The obligations are expected to be funded from the Company’s internal resources available at the time of settlement.

The total decommissioning and environmental liability is estimated based on the Company’s net ownership in wells drilled as at December 31, 2020, the estimated costs to abandon and reclaim the wells and well sites and the estimated timing of the costs to be paid in future periods. The total undiscounted amount of cash flows required to settle the Company’s decommissioning liability is approximately $60.4 million as at December 31, 2020 (December 31, 2019 - $63.3 million) with the majority of these costs anticipated to occur in 2033 or later. A risk-free discount rate of 5.25% and an inflation rate of 2.0% were used in the valuation of the liabilities (December 31, 2019 - 6.74% risk-free discount rate and a 3.1% inflation rate). The risk-free discount rate and the inflation rate used in 2020 are based on forecast Colombia rates.

Included in the decommissioning liability is $3.6 million (December 31, 2019 - $4.3 million) that is classified as a current obligation.

The total undiscounted amount of cash flows required to settle the Company’s environmental liability is approximately $20.5 million as at December 31, 2020 (December 31, 2019 - $21.5 million) with the majority of these costs anticipated to occur in 2033 or later in Colombia. A risk-free discount rate of 5.25% and an inflation rate of 2.0% were used in the valuation of the liabilities (December 31, 2019 - 6.74% risk-free discount rate and a 3.1% inflation rate). The risk-free discount rate and the inflation rate used in 2020 are based on forecast Colombia rates.

Included in the environmental liability is $3.4 million (December 31, 2019 - $4.1 million) that is classified as a current obligation.

Decommissioning and environmental liabilities are considered critical accounting estimates. There are significant uncertainties related to decommissioning and environmental expenditures and the impact on the financial statements could be material. The eventual timing of and costs for these expenditures could differ from current estimates. The main factors that can cause expected estimated cash flows in respect of decommissioning and environmental liabilities to change are:

• Changes in laws, legislation and regulations;

• Construction of new facilities;

• Change in commodity price;

• Change in the estimate of oil reserves and the resulting amendment to the life of reserves;

• Changes in technology; and

• Execution of decommissioning and environmental liabilities.

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22

December 31, 2020

Advisory on Forward-Looking Statements

Certain information regarding Parex set forth in this MD&A, including assessments by the Company’s management of the Company’s plans and future operations, contains forward-looking statements that involve substantial known and unknown risks and uncertainties. The use of any of the words “plan”, “expect”, “forecast”, “project”, “intend”, “believe”, “anticipate”, “estimate” or other similar words, or statements that certain events or conditions “may” or “will” occur are intended to identify forward-looking statements. Such statements represent the Company’s internal projections, estimates or beliefs concerning, among other things, future growth, results of operations, production, future capital and other expenditures (including the amount, nature and sources of funding thereof), competitive advantages, plans for and results of drilling activity, environmental matters, business prospects and opportunities. These statements are only predictions and actual events or results may differ materially. Although the Company’s management believes that the expectations reflected in the forward-looking statements are reasonable, it cannot guarantee future results, levels of activity, performance or achievement since such expectations are inherently subject to significant business, economic, competitive, political and social uncertainties and contingencies. Many factors could cause the Company’s actual results to differ materially from those expressed or implied in any forward-looking statements made by, or on behalf of, Parex. In particular, forward-looking statements contained in this MD&A include, but are not limited to, statements with respect to:

• ▪the Company's operational strategy, plans, priorities and focus;

• ▪2021 guidance for Brent crude average price, average production, total capital expenditures, funds flow provided by operations, free funds flow, amount spent on the Company's share buy-back program, outstanding shares at end of the applicable period, production per share growth, estimated working capital at end of the applicable period, bank debt outstanding at end of applicable period, operating netback, FFO netback and current tax effective rate on FFO and assumptions underlying such estimates and guidance;

• ▪expectation that Parex will purchase the maximum allowable shares under its normal course issuer bid and assumptions as to average share price;

• ▪Parex' 2021 NCIB and the sources of funding;

• ▪Expected Q1 2021 average production;

• ▪Parex' strong financial position and the benefits to be derived thereunder;

• ▪fluctuation in Brent/Vasconia crude differential;

• ▪expectation that crude oil inventory in future periods to be in line with normal historic levels;

• ▪the timing of payment of total decommissioning and environmental liability cost and the internal resources available at the time of settlement;

• ▪the Company’s expectations regarding the per boe and G&A expense impact caused by appreciation and depreciation of the Colombian peso;

• ▪the effect of the Colombian peso/US$ exchange rate on the variability of general and administrative, transportation costs and production costs;

• ▪foreign currency risk and the ability to reverse unrealized foreign exchange gains and losses in the future;

• ▪the Company's risk management strategy and the fluctuation of earnings based on strip prices;

• ▪terms of the Company's credit facility including the timing of the next borrowing base redetermination;

• ▪no plans to utilize the credit facility in 2021;

• ▪terms of certain contractual obligations;

• ▪the Company's expectation that only the grants under the Company's stock option plan and exercise of previously issued RSUs and PSUs will result in common shares issued from treasury;

• ▪the Company's expectation that the next redetermination of its credit facility will not impact its current or future operations or reduce the 2021 outlook;

• ▪estimated amounts, timing and the anticipated sources of funding for the Company's exploration, office and accommodations, environmental, decommissioning and restoration obligations.

• ▪the statements set forth under "Accounting Policies and Estimates" in this MD&A.

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23

December 31, 2020

These forward-looking statements are subject to numerous risks and uncertainties, including but not limited to: the impact of general economic conditions in Canada and Colombia; impact of the COVID-19 pandemic and the ability of the Company carry on its operations as currently contemplated in light of the COVID-19 pandemic; determination by OPEC and other country as to production levels; industry conditions including changes in laws and regulations including adoption of new environmental laws and regulations, and changes in how they are interpreted and enforced in Canada and Colombia; continued volatility in market prices for oil; the impact of significant declines in market prices for oil; competition; lack of availability of qualified personnel; the results of exploration and development drilling and related activities; partner approval of capital work programs and other matters requiring approval; imprecision in reserve and resource estimates; the production and growth potential of Parex’ assets; obtaining required approvals of regulatory authorities in Canada and Colombia; risks associated with negotiating with foreign governments as well as country risk associated with conducting international activities; fluctuations in foreign exchange or interest rates; environmental risks; changes in income tax laws or changes in tax laws and incentive programs relating to the oil and natural gas industry; ability to access sufficient capital from internal and external sources; risk that the Company will not be able to obtain contract extensions or fulfill the contractual obligations required to retain its rights to explore, develop and exploit any of its undeveloped properties; risk of failure to achieve the anticipated benefits associated with acquisitions; risk of failure to achieve perceived benefits from voluntary tax restructuring; failure of counterparties to perform under the terms of their contracts; changes to pipeline capacity; risk that Parex' evaluation of its existing portfolio of development and exploration opportunities is not consistent with its expectations; failure to meet expected production targets; the risks discussed under "Risk Factors" in the Company’s AIF and under “Decommissioning and Environmental Liabilities” in this MD&A, and other factors, many of which are beyond the control of the Company. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect the Company’s operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com).

Although the forward-looking statements contained in this MD&A are based upon assumptions which management believes to be reasonable, the Company cannot assure investors that actual results will be consistent with these forward-looking statements. With respect to forwardlooking statements contained in this MD&A, Parex has made assumptions regarding, among other things: current and future commodity prices and royalty regimes; the impact (and the duration thereof) that the COVID-19 pandemic will have on the demand for crude oil and natural gas, Parex' supply chain and Parex' ability to produce, transport and sell Parex crude oil and natural gas; availability of skilled labour; timing and amount of capital expenditures; uninterrupted access to areas of the Company’s operations and infrastructure; future exchange rates; the price of oil; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment; effects of regulation by governmental agencies; recoverability of reserves and future production rates; timing and number of dry hole write-offs permitted for Colombian tax purposes; royalty rates; future operating costs; foreign exchange rates; the status of litigation; timing of drilling and completion of wells; that the Company will have sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and operating expenditures and requirements as needed; that the Company’s conduct and results of operations will be consistent with its expectations; that the Company will have the ability to develop the Company’s oil and gas properties in the manner currently contemplated; current or, where applicable, proposed industry conditions, laws and regulations will continue in effect or as anticipated as described herein; that the estimates of the Company’s reserves volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects; that the Company will be able to obtain contract extensions or fulfill the contractual obligations required to retain its rights to explore, develop and exploit any of its undeveloped properties; on-stream timing of production from successful exploration wells; operational performance of non-operated producing fields; pipeline capacity; and other matters. The ability of the Company to carry out its business plan is primarily dependent upon the continued support of its shareholders, the discovery of economically recoverable reserves and the ability of the Company to obtain financing or generate sufficient cash flow to develop such reserves.

Forward-looking statements and other information contained in this MD&A concerning the oil and natural gas industry in the countries in which it operates and the Company's general expectations concerning this industry are based on estimates prepared by Management using data from publicly available industry sources as well as from resource reports, market research and industry analysis and on assumptions based on data and knowledge of this industry which the Company believes to be reasonable. However, this data is inherently imprecise, although generally indicative of relative market positions, market shares and performance characteristics. While the Company is not aware of any material misstatements regarding any industry data presented herein, the oil and natural gas industry involves numerous risks and uncertainties and is subject to change based on various factors.

Management has included forward looking information and the above summary of assumptions and risks related to forward-looking information in this MD&A in order to provide shareholders with a more complete perspective on the Company’s current and future operations and such information may not be appropriate for other purposes. The Company’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do, what benefits Parex will derive there from. These forward-looking statements are made as of the date of this MD&A and Parex disclaims any intent or obligation to update publicly any forwardlooking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.

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24

December 31, 2020

This MD&A may contain future oriented financial information ("FOFI") within the meaning of applicable securities laws. The FOFI has been prepared by management to provide an outlook of the Company's activities and results and may not be appropriate for other purposes. The FOFI has been prepared based on a number of assumptions including the assumptions discussed above. The actual results of operations of the Company and the resulting financial results may vary from the amounts set forth herein, and such variations may be material. The Company and management believe that the FOFI has been prepared on a reasonable basis, reflecting management’s best estimates and judgments. FOFI contained in this MD&A was made as of the date of this MD&A and the Company disclaims any intention or obligations to update or revise any FOFI contained in this MD&A, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law.

Non-GAAP Terms

This report contains financial terms that are not considered measures under GAAP such as operating netback, operating netback per boe, funds flow provided by operations, funds flow provided by operations per boe, funds flow netback per boe, free funds flow and diluted funds flow per share that do not have any standardized meaning under IFRS and may not be comparable to similar measures presented by other companies. Management uses these non-GAAP measures for its own performance measurement and to provide shareholders and investors with additional measurements of the Company’s efficiency and its ability to fund a portion of its future capital expenditures.

Adoption of IFRS 16 Leases had an immaterial impact on netbacks, funds flow provided by operations and EBITDA non-GAAP measures.

Funds flow provided by operations, is a non-GAAP measure that includes all cash generated from operating activities and is calculated before changes in non-cash working capital. In Q2 2019, the Company changed how it presents funds flow provided by operations to present on a comparable basis to peer presentation. Amounts have been restated for prior periods. A reconciliation from cash provided by operating activities to funds flow provided by operations is as follows:

		For the three months	For the three months	For the three months		For the year ended	For the year ended	For the year ended
		ended December 31,				December 31,
($000s)		2020		2019		2020		2019
Cash provided by operating activities	$	86,988	$	83,766	$	290,018	$	365,067
Net change in non-cash workingcapital		**(5,421) **		59,503		7,023		205,413
Funds flowprovided by operations		81,567		143,269		297,041		570,480

Funds flow provided by operations per boe or funds flow netback per boe , is a non-GAAP measure that includes all cash generated from operating activities and is calculated before changes in non-cash working capital, divided by produced oil and natural gas sales volumes. The Company considers funds flow netback to be a key measure as it demonstrates Parex’ profitability after all cash costs relative to current commodity prices and is calculated as follows:

		For the three	months ended	months ended		For the year	For the year	ended
		December		31,		December		31,
($000s)		2020		2019		2020		2019
Funds flowprovided by operations	$	81,567	$	143,269	$	297,041	$	570,480
Company produced oil and naturalgas sales inperiod		4,279,656		5,136,452	16,954,264			19,265,365
Funds flowprovided by operationsper boe		19.06		27.89		17.52		29.61

Free funds flow, is a non-GAAP measure that is determined by funds flow provided by operations less capital expenditures. The Company considers free funds flow or free cash flow to be a key measure as it demonstrates Parex’ ability to fund return of capital, such as the NCIB, without accessing outside funds and is calculated as follows:

		For the three	months	ended		For the year ended	For the year ended	For the year ended
		December 31,				December 31,
($000s)		2020		2019		2020		2019
Funds flow provided by operations	$	81,567	$	143,269	$	297,041	$	570,480
Capital expenditures,excludingcorporate acquisitions		46,932		58,321		141,264		208,196
Free funds flow	$	34,635	$	84,948	$	155,777	$	362,284

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December 31, 2020

Diluted funds flow per share is calculated by dividing funds flow provided by operations by the weighted average number of shares outstanding. Parex presents diluted funds flow provided by operations per share whereby per share amounts are calculated using weightedaverage shares outstanding, consistent with the calculation of earnings per share. The following table shows the variables used in the calculation of diluted funds flow per share:

		For the three	months	ended		For the year ended	For the year ended	For the year ended
		December 31,				December 31,
($000s)		2020		2019		2020		2019
Funds flowprovided by operations	$	81,567	$	143,269	$	297,041	$	570,480
Weighted average number of shares for the purposes of basic funds flow		133,812		142,967		138,356		146,380
Dilutive effect of share options onpotential common shares		1,372		2,598		1,263		2,645
Weighted average number of shares for the purposes of diluted
funds flow		135,184		145,565		139,619		149,025

Adjusted EBITDA is defined as net income (loss) before interest, taxes, depletion and depreciation and adjusted for other non-cash items, transaction costs and extraordinary and non-recurring items. Adjusted EBITDA is solely used in the calculation of the bank covenant and is not considered a key performance measure by Management.

Operating netback per boe

The Company considers operating netbacks to be a key measure as they demonstrate Parex’ profitability relative to current commodity prices. Below is a description of each component of the Company's operating netback and how it is determined.

Oil and natural gas sales per boe is determined by sales revenue excluding risk management contracts divided by total equivalent sales volume including purchased oil volumes. A reconciliation of the calculation of oil and natural gas sales per boe is provided below:

		For the three	months ended	months ended		For the year	For the year	ended
		December		31,		December		31,
($000s)		2020		2019		2020		2019
Oil and naturalgas revenue excludingrisk management contracts	$	167,264	$	289,585	$	587,520	$	1,113,622
Oil revenue forpurposes of salespriceper boe	$	167,264	$	289,585	$	587,520	$	1,113,622
Denominator(BOEs)
Company produced oil and natural gas sales in period		4,279,656		5,136,452	16,954,264			19,265,365
Purchased oil volumes sold		247,296		327,612		1,097,971		1,091,580
Total oil and naturalgas sales volumes		4,526,952		5,464,064	18,052,235			20,356,945
Salespriceper boe	$	36.95	$	53.00	$	32.55	$	54.70

Royalties per boe is determined by dividing royalty expense by the total equivalent sales volume and excludes purchased oil volumes. A reconciliation of royalties per boe is provided below:

		For the three	months ended	months ended		For the year	For the year	ended
		December		31,		December		31,
($000s)		2020		2019		2020		2019
Royalty expense	$	13,642	$	36,717	$	55,655	$	136,068
Denominator(BOEs)
Company produced oil and naturalgas sales inperiod		4,279,656		5,136,452	16,954,264			19,265,365
Royalty expenseper boe	$	3.19	$	7.15	$	3.28	$	7.06

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December 31, 2020

Production expense per boe is determined by dividing production expense by the total equivalent sales volume and excludes purchased oil volumes. A reconciliation of production expense per boe is provided below:

		For the three	months ended	months ended		For the year	For the year	ended
		December		31,		December		31,
($000s)		2020		2019		2020		2019
Production Expense	$	22,499	$	29,183	$	87,272	$	111,061
Denominator(BOEs)
Company produced oil and naturalgas sales inperiod		4,279,656		5,136,452	16,954,264			19,265,365
Production expenseper boe	$	5.26	$	5.68	$	5.15	$	5.76

Transportation expense per boe is determined by dividing the transportation expense by the total equivalent sales volumes including purchased oil volumes. A reconciliation of transportation expense per boe is provided below:

		For the three	months ended	months ended		For the year	For the year	ended
		December		31,		December		31,
($000s)		2020		2019		2020		2019
Transportation Expense	$	16,938	$	20,462	$	59,147	$	88,974
Denominator(BOEs)
Company produced oil and natural gas sales in period		4,279,656		5,136,452	16,954,264			19,265,365
Purchased oil volumes sold		247,296		327,612		1,097,971		1,091,580
Total oil and naturalgas sales volumes		4,526,952		5,464,064	18,052,235			20,356,945
Transportation expenseper boe	$	3.74	$	3.74	$	3.28	$	4.37

Environmental Initiatives Impacting Parex

In Colombia there is currently no specific regulation that obliges companies to specifically monitor and report GHG emissions. However in 2017, the Colombian government submitted a bill which sets guidelines to manage climate change, although very little specifics were provided. Although at the present time there is no specific regulations related to climate change or GHG emissions in Colombia, Parex has a plan in place to monitor and disclose key metrics surrounding the environmental impacts of Parex' operations. Climate change regulation in Colombia has the potential to significantly affect the regulatory environment of the crude oil and natural gas industry in Colombia. Such regulations impose certain costs and risks on the industry, and there remains some uncertainty with regard to the impact of climate change and environmental laws and regulations on Parex, as Parex is unable to predict additional legislation or amendments that the Colombian government may enact in the future. Any new laws and regulations, or additional requirements to existing laws and regulations, could have a material impact on the Company's operations and cash flow.

Business Environment and Risks

Overall

Parex is exposed to a variety of risks including but not limited to operational, financial, competitive, political and environmental risks. As a participant in the oil and natural gas industry, Parex is exposed to operational risks such as: unsuccessful exploration and exploitation activities, the inability to find new reserves that are commercially and economically feasible, premature declines of reservoirs, well blow-outs and other operating hazards, and lack of infrastructure or transportation to access markets and monetize reserves. The Company works to mitigate these risks by employing highly skilled personnel and utilizing available technology. The Company also maintains a corporate insurance program consistent with industry practices to protect against insurable losses.

The Company is exposed to normal financial risks inherent in the oil and natural gas industry including: commodity price risk, exchange rate risk, interest rate risk and credit risk. The Company continuously monitors opportunities to use financial instruments to manage exposure to fluctuations in commodity prices, foreign currency rates and interest rates. Parex operates the majority of its properties and, therefore, has significant control over the timing, direction and costs related to exploration commitments and development opportunities.

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December 31, 2020

COVID-19

The COVID-19 pandemic has resulted in emergency actions taken by governments worldwide which has had an effect in all of the Company's operating jurisdictions. The actions taken by these governments have typically included, but is not limited to travel bans, mandatory and selfimposed quarantines and isolations, social distancing, and the closing of non-essential businesses which has had significant negative effects on economies, including a substantial decline in crude oil and natural gas demand. Additionally, such actions have resulted in volatility and disruptions in regular business operations, supply chains and financial markets as well as declining trade and market sentiment. COVID-19 as well as other factors have resulted in the deepest drop in crude oil prices that global markets have seen since 1991. With the rapid spread of COVID-19, oil prices and the global equity markets deteriorated significantly in 2020. Despite the approval of certain vaccines by the regulatory bodies in Canada and the U.S., the ongoing evolution of the development and distribution of an effective vaccine also continues to raise uncertainty and global equity markets could remain under pressure. The supply/demand imbalance is anticipated to cause a reduction in industry spending in 2021. These events and conditions caused a significant decrease in the valuation of oil and natural gas companies in 2020 and a decrease in confidence in the oil and natural gas industry. COVID-19 also poses a risk on the financial capacity of Parex' contract counterparties and potentially their ability to perform contractual obligations.

The full extent of the risks surrounding the COVID-19 pandemic is continually evolving in light of an effective distribution of the vaccine and also through subsequent waves, or it additional variants of COVID-19 continue to emerge which are more transmissible or cause more severe disease. The following risks disclosed in the Company's Annual Information Form for the year ended December 31, 2020 may be exacerbated as a result of the COVID-19 pandemic: market risks related to the volatility of oil and gas prices, volatility of foreign exchange rates, volatility of the market price of common shares, and hedging arrangements; operational risks related to increasing operating costs or declines in production levels, operator performance and payment delays, and government regulations, ability to obtain additional financing, and variations in foreign exchange rates; and other risks related to cyber-security as the Company's workforce moves to remote connections, accounting adjustments, effectiveness of internal controls, and reliance on key personnel, management, and labour.

Changing Investor Sentiment

A number of factors, including the concerns of the effects of the use of fossil fuels on climate change, the impact of oil and gas operations on the environment, environmental damage relating to spills of petroleum products during transportation and indigenous rights, have affected certain investors' sentiments towards investing in the oil and gas industry. As a result of these concerns, some institutional, retail and public investors have announced that they no longer are willing to fund or invest in oil and gas properties or companies or are reducing the amount thereof over time. In addition, certain institutional investors are requesting that issuers develop and implement more robust social, environmental and governance policies and practices. Developing and implementing such policies and practices can involve significant costs and require a significant time commitment from the Board, management and employees of the Company. Failing to implement the policies and practices as requested by institutional investors may result in such investors reducing their investment in the Company or not investing in the Company at all. Any reduction in the investor base interested or willing to invest in the oil and gas industry and more specifically, the Company, may result in limiting the Company's access to capital, increasing the cost of capital, and decreasing the price and liquidity of the Common Shares even if the Company's operating results, underlying asset values or prospects have not changed. Additionally, these factors, as well as other related factors, may cause a decrease in the value of the Company's assets which may result in an impairment change.

The Company's workforce may be exposed to widespread pandemic

Parex' operations are located in areas relatively remote from local towns and villages and represent a concentration of personnel working and residing in close proximity to one another. Should an employee or visitor become infected with a serious illness that has the potential to spread rapidly, this could place Parex' workforce at risk. The 2020 outbreak of the novel coronavirus (COVID-19) in China and other countries around the world is one example of such an illness. The Company takes every precaution to strictly follow industrial hygiene and occupational health guidelines. There can be no assurance that this virus, virus variants or another infectious illness will not impact Parex' personnel and ultimately its operations.

Foreign Jurisdiction Political Risk

Parex is focused on international oil and natural gas exploration and production activities in Colombia. As such, the Company is subject to potential political risks such as: changes in polices and regulation related to changes in government, price controls, renegotiation of land tenure agreements, nationalization, changes in tax and royalty regulations, amendments or changes to legal systems, and complex regulatory regimes. The Company focuses its foreign operations in countries where management has prior experience and/or engages local in-country staff as soon as possible. The Company engages local, Canadian and international advisors. The Company may also, from time to time, arrange for insurance to mitigate specific risks. The Company is also exposed to potential delay of its operations due to waiting on permits or obtaining surface access to drilling locations.

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December 31, 2020

Venezuela Presidential Crisis

A crisis concerning who is the legitimate President of Venezuela has been underway since January 10th, 2019, when the opposition-majority National Assembly declared that incumbent Nicolás Maduro's 2018 re-election was invalid and the body declared its president, Juan Guaidó, to be acting president of the nation. As of February 2019, Guaidó is recognized as the interim president of Venezuela by more than 50 countries including the United States and most Latin American and European countries. Maduro's government states that the crisis is a "coup d'état" led by the United States to topple him and control the country's oil reserves." Guaidó denies the coup allegations, saying peaceful volunteers back his movement.

The crisis has had a profound impact on the people of Venezuela and its neighboring countries including Colombia. At this time, it is unknown what the impact will be on the regions oil markets, and Colombia foreign relations and politics.

The Capachos block, which the Company operates is 75 km from the Venezuelan border to Colombia in the department of Arauca. The Company is monitoring the situation closely but to date has not seen any material impacts of the crises on the operations of the Company however, it cannot be foreseen whether this will change in the future.

Security in Colombia

A 50-year armed conflict between government forces and anti-government insurgent groups and illegal paramilitary groups, both thought to be funded by the drug trade, continues in Colombia. Insurgents continue to attack civilians and violent guerrilla activity continues in certain parts of the country. Regions that border Venezuela and Ecuador have historically been areas of high security risk and there continues to be guerrilla activity.

Continuing attempts to reduce or prevent guerrilla activity may not be successful and guerrilla activity may disrupt Parex Colombia operations in the future. The Company may not be able to establish or maintain the safety of its operations and personnel in Colombia and this violence may affect its operations in the future. Continued or heightened security concerns in Colombia could also result in a significant loss to Parex and/or costs exceeding current expectations.

Reserves Estimates

Parex has retained an independent engineering consulting firm that assists the Company in evaluating oil and natural gas reserves on an annual basis. Reserve values are based on a number of variables and assumptions such as future commodity prices, projected production, future production costs and governmental regulations. Reserve estimates are prepared in accordance with standards and procedures set out in the COGE and NI 51-101. The reserves and recovery information contained in the independent reserve report is an estimate. The actual production and ultimate reserves from the properties may be greater or less than the estimates prepared by the independent reserve engineers.

Volatility of Commodity Prices and Foreign Exchange Rates

The Company’s operational results and financial condition depend on the prices received for petroleum production. Commodity prices are determined by economic and, in some circumstances, political factors. Supply and demand factors, including weather and general economic conditions as well as conditions in other oil and natural gas regions, also influence prices. Parex is exposed to commodity price risk whereby the fair value of future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for petroleum are affected by the global economic events that dictate the levels of supply and demand. As at the date of this MD&A, Parex has no active crude oil hedges in place (see “Risk Management Contracts – Brent Crude”).

Foreign currency risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate as a result of changes in foreign currency exchange rates. The Company is exposed to foreign currency fluctuations as various portions of its cash balances and future expenses and revenues are denominated in Colombian pesos (COP) and Canadian dollars (Cdn$). As at the date of this MD&A, Parex does not have active foreign exchange hedges in place (see “Risk Management Contracts – Foreign Exchange”).

Counterparty Risk

Credit risk is the risk of a counterparty failing to meet its obligations in accordance with the agreed upon terms. The Company may be exposed to third-party credit risk through its contractual arrangements with its current or future joint venture partners, marketers of its commodities and other parties. Parex has established credit policies and controls designed to mitigate the risk of default or non-payment with respect to oil and natural gas sales, financial hedging transactions and joint venture participants. The Company makes every effort to sell its commodities to major companies with excellent credit ratings and/or managing its crude production on a portfolio basis.

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December 31, 2020

Access to Capital

From time to time, the Company may have to raise additional funds to finance business development activities. Parex’ ability to raise additional capital will depend on a number of factors such as general economic and market conditions that are beyond the Company’s control. Internally generated funds will also fluctuate with changing commodity prices. Parex currently has a $200.0 million syndicated credit facility with three banks. The Company is required to comply with covenants under this facility and in the event it does not comply, access to capital could be restricted or repayment may be required. At the date of this MD&A bank debt was $nil. Parex routinely reviews the covenants based on actual and forecasted results and has the ability to make changes to development and exploration plans to comply with the covenants under the credit facility. Parex is committed to maintaining a strong balance sheet, which at current has available working capital, along with an adaptable capital expenditure program that can be adjusted to capitalize on, or reflect acquisition opportunities and, if necessary a tightening of liquidity sources. From the company’s founding to the date of this MD&A, Parex has had no defaults or breaches on its bank debt or any of its financial liabilities.

Operational Matters

The oil and natural gas industry is intensely competitive, with Parex competing against companies that may have greater technical and financial resources. There is competition for new exploration and development properties, for infrastructure and sales contracts, for drilling and other specialized technical equipment and for experienced key human resources. As appropriate, Parex seeks to enter into joint venture arrangements with large and/or experienced industry players.

There are also extensive and varying environmental regulations imposed by the governments in the countries in which Parex operates. The Company adopts prudent and industry-recommended field operating procedures in all of its operations, as well as maintaining a health, safety and environment program.

Exploration

The Company is exposed to a high level of exploration risk. The Company’s current and future (to the extent discovered or acquired) proved reserves will decline as reserves are produced from its properties unless the Company is able to acquire or develop new reserves. The business of exploring for, developing or acquiring reserves is capital-intensive and is subject to numerous estimates and interpretations of geological and geophysical data. There can be no assurance that the Company’s future exploration, development and acquisition activities will result in material additions of proved reserves. To manage this risk, to the extent possible, Parex employs highly experienced geologists and geophysicists, uses technology such as 3D seismic as a primary exploration tool and focuses exploration efforts in known hydrocarbonproducing basins. In addition, the Company takes a portfolio approach to exploration by dispersing drilling locations among different exploration blocks and geological basins and by targeting multiple play-types. The Company may also choose to mitigate exploration risk through acquisitions that may require raising funds.

Cyber-Security

The Company is subject to a variety of information technology and system risks as a part of its normal course operations, including potential breakdown, invasion, virus, cyber-attack, cyber-fraud, security breach, and destruction or interruption of the Company's information technology systems by third parties or insiders. Although the Company has security measures and controls in place that are designed to mitigate these risks, a breach of its security measures and/or a loss of information could occur and result in a loss of material and confidential information and reputation, breach of privacy laws and a disruption to its business activities. The significance of any such event is difficult to quantify, but may in certain circumstances be material and could have a material adverse effect on the Company's business, financial condition and results of operations. Parex relies on information technology, such as computer hardware and software systems, in order to properly operate its business. In the event the Company is unable to regularly deploy software and hardware, effectively upgrade systems and network infrastructure, and take other steps to maintain or improve the efficiency and efficacy of systems, the operation of such systems could be interrupted or result in the loss, corruption, or release of data. In addition, information systems could be damaged or interrupted by natural disasters, force majeure events, telecommunications failures, power loss, acts of war or terrorism, computer viruses, malicious code, physical or electronic security breaches, intentional or inadvertent user misuse or error, or similar events or disruptions. Any of these or other events could cause interruptions, delays, loss of critical or sensitive data or similar effects, which could have a material adverse impact on the protection of intellectual property, and confidential and proprietary information, and on Parex’ business, financial condition, results of operations and funds flow from operations.

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December 31, 2020

Internal Controls over Financial Reporting

Disclosure controls and procedures (“DC&P”), as defined in National Instrument 52-109 Certification of Disclosure in Issuers’ Annual and Interim Filings , are designed to provide reasonable assurance that information required to be disclosed in annual filings, interim filings or other reports filed, or submitted by the Company under securities legislation authorities is recorded, processed, summarized and reported within the time periods specified in the securities legislation and include controls and procedures designed to ensure that information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted under securities legislation is accumulated and communicated to the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. The Chief Executive Officer and the Chief Financial Officer of Parex evaluated the effectiveness of the design and operation of the Company’s DC&P. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded Parex DC&P were effective as at December 31, 2020.

Internal control over financial reporting (“ICFR”), as defined in National Instrument 52-109, includes those policies and procedures that:

• 1) Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets of Parex;

• 2) Are designed to 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 Parex are being made in accordance with authorizations of management and Directors of Parex; and

• 3) Are designed to 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 annual financial statements or interim financial reports.

The Chief Executive Officer and the Chief Financial Officer are responsible for establishing and maintaining ICFR for Parex. They have, as at the financial year ended December 31, 2020, designed ICFR, or caused it to be designed under their supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. The control framework Parex officers used to design the Company’s ICFR is the 2013 Internal Control - Integrated Framework (“COSO Framework”) published by The Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Under the supervision of the Chief Executive Officer and the Chief Financial Officer, Parex conducted an evaluation of the effectiveness of the Company’s ICFR as at December 31, 2020 based on the COSO Framework. Based on this evaluation, the officers concluded that as of December 31, 2020, Parex maintained effective ICFR. It should be noted that while Parex officers believe that the Company’s controls provide a reasonable level of assurance with regard to their effectiveness, they do not expect that the DC&P and ICFR will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, but not absolute, assurance that the objectives of the control system are met.

There were no changes in Parex’ ICFR during the year ended December 31, 2020 that materially affected, or are reasonably likely to materially affect, the Company’s ICFR.

Off-Balance-Sheet Arrangements

The Company did not enter into any off-balance-sheet arrangements during the twelve months ended December 31, 2020.

Financial Instruments and Other Instruments

The Company’s non-derivative financial instruments recognized in the consolidated balance sheet consist of cash, accounts receivable, accounts payable and accrued liabilities. Non-derivative financial instruments are recognized initially at fair value. The fair values of the current financial instruments approximate their carrying value due to their short-term maturity.

Related Party Transactions

Compensation of Key Management Personnel

Key management personnel compensation, including directors, is as follows:

		2020		2019
Salaries, directors' fees and other benefits	$	4,515	$	4,241
Equity settled share-based compensation		1,613		3,714
Cash settled share-based compensation		1,451		4,934
	$	7,579	$	12,889

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December 31, 2020

At December 31, 2020 key management personnel are comprised of the Company’s directors and eight executives. As at December 31, 2020, there is a Cdn$9.1 million commitment relating to change of control or termination of employment of the eight executives (December 31, 2019 - Cdn$8.9 million for the seven executives).

Other related party transactions

The Company did not have any related party transactions with entities outside the consolidated group for the years ended December 31, 2020 and 2019.

Significant Accounting Policies

Refer to note 3 - Summary of Significant Accounting Policies of the December 31, 2020 consolidated financial statements for a summary of significant accounting policies applied by the Company.

Significant Accounting Estimates

The preparation of consolidated financial statements in accordance with IFRS requires management to make significant judgments, assumptions and estimates that affect the financial results of the Company. The following discussion outlines the accounting policies and practices involving the use of estimates that the Company believes are critical in determining Parex’ financial results.

Oil and natural gas reserves

The Company retains qualified independent reserves evaluators to evaluate the Company’s proved and probable oil and natural gas reserves. As at December 31, 2020 and in prior periods, Parex’ reserves were evaluated by GLJ Ltd., who are a firm of qualified independent reserves evaluators. The evaluation was conducted in accordance with the COGE handbook and NI 51-101. The Operations and Reserves Committee of the Company’s Board of Directors is comprised of independent directors whose mandate is to steward the reserves evaluation process.

The estimation of reserves involves the exercise of judgment. Forecasts are based on engineering data, expected rates of production and the timing of future capital expenditures, all of which are subject to major uncertainties and interpretations. The Company expects that over time its reserve estimates will be revised upward or downward based on updated information such as the results of future drilling, testing and production levels. Reserve estimates can have a significant impact on net income, as they are a key component in the calculation of DD&A and for determining potential asset impairment. A downward revision in reserves estimates or an increase in estimated future development costs could result in the recognition of a higher DD&A charge to net income.

Oil and natural gas assets (development and producing costs) are aggregated into CGUs based on their ability to generate largely independent cash flows. If the carrying value of the CGU exceeds the recoverable amount, the CGU is written down with an impairment recognized in net income. The recoverable amount of an asset or CGU is the greater of its fair value less costs to sell and its value in use. Fair value less costs to sell may be determined using discounted future net cash flows of proved plus probable reserves using forecast prices and costs. A downward revision in reserves estimates could result in the recognition of impairments charged to net income.

Reversals of impairments are recognized when there has been a subsequent increase in the recoverable amount. In this event, the carrying amount of the asset or CGU is increased to its revised recoverable amount with an impairment reversal recognized in net income.

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December 31, 2020

Decommissioning and environmental liabilities

The Company is required to recognize a liability for future dismantling, decommissioning, environmental, abandoning and site disturbance remediation costs associated with the Company's oil and natural gas properties in accordance with existing laws, contracts or other policies. The fair value of the estimated decommissioning and environmental liability is recorded as a long-term liability, with a corresponding increase in the carrying amount of the related long-lived asset, which is depleted on a unit-of-production basis over the life of the reserves. The liability is adjusted each reporting period to reflect the passage of time, with the accretion charged to net income, and for revisions to the estimated future cash flows. Actual costs incurred upon settlement of the obligations are charged against the liability.

Decommissioning and environmental liabilities are determined by using management’s best estimate of costs, taking into account the anticipated method and extent of restoration consistent with legal requirements, technological advances, industry practices and the possible use of the site. Since these estimates are specific to the sites involved, there are many individual assumptions underlying the Company’s total decommissioning and environmental liability. These individual assumptions can be subject to change based on experience. Restoration technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. The Company estimates future decommissioning and environmental costs based on current estimates adjusted for inflation. This estimate for inflation is also subject to management uncertainty.

Current and Deferred tax

The Company follows the liability method of accounting for income taxes. Under this method, future tax assets and liabilities are determined based on differences between the financial reporting and tax basis of assets and liabilities and are measured using substantially enacted tax rates and laws that will be in effect when the differences are expected to reverse. The effect of a change in income tax rates on deferred tax liabilities and assets is recognized in net income in the period that the change occurs. Deferred tax assets are only recognized to the extent that it is probable that sufficient future taxable income will be available in the applicable jurisdiction to allow the deferred tax assets to be realized.

The determination of the Company’s income and other tax liabilities requires interpretation of complex laws and regulations from multiple jurisdictions. Rates are also affected by legislative changes. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded in the financial statements. Estimates of current income tax for interim periods are also subject to additional uncertainty. A variety of factors cannot be known until year-end and, therefore, estimates are used for interim period current tax provisions.

Share-based compensation

The Company records stock-based compensation expense using the fair value method. The fair value of an option is calculated at the grant date, and expensed equally over the vesting term of the option. The Company records the cumulative stock-based compensation as contributed surplus. When options are exercised, contributed surplus is reduced and share capital is increased by the amount of accumulated stock-based compensation for the exercised option. Any consideration received on the exercise of stock options is credited to share capital.

The determination of stock-based compensation expense is based on assumptions regarding stock volatility, risk-free interest rates and the expected life of the options. These assumptions, by their nature, are subject to measurement uncertainty.

Obligations for payments of cash under the subsidiaries’ SARs plan are accrued as compensation expense over the vesting period based on the fair value of SARs, subject to appreciation limits specified in the plan. The fair value of SARs is measured using the Black-Scholes pricing model. In accordance with the fair value method, increases or decreases in the fair value of the SARs result in a corresponding change in the recorded liability. The accrued compensation for a right that is forfeited is adjusted by decreasing compensation cost in the period of forfeiture.

The determination of SARs expense is based on assumptions regarding stock volatility, risk-free interest rates and the expected life of the SAR. These assumptions, by their nature, are subject to measurement uncertainty.

The fair value of an RSU, PSU and CRSU is calculated using the market price of Parex shares on the date of issuance, and expensed over the vesting period of the RSU, PSU or CRSU.

In accordance with the fair value method, increases or decreases in the fair value of the CRSUs result in a corresponding change in the recorded liability. The accrued compensation for a right that is forfeited is adjusted by decreasing compensation cost in the period of forfeiture.

PSUs may be granted with certain performance measures, specified at the grant date as determined by the Company's Board of Directors. Based upon the achievement of the performance measures, a pre-determined adjustment factor of between 0-2x is applied to PSUs eligible to vest at the end of the performance period. The expense recognized over the vesting period of PSUs is the fair value of the PSUs with an estimated adjustment factor.

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December 31, 2020

The fair value of a DSU is calculated using the market price of Parex shares on the date of issuance, and expensed immediately. In accordance with the fair value method, increases or decreases in the fair value of the DSUs result in a corresponding change in the recorded liability. The accrued compensation for a right that is forfeited is adjusted by decreasing compensation cost in the period of forfeiture.

Obligations for payments of cash under the CosRSUs and CosPSUs plans are accrued as compensation expense over the vesting period based on the fair value of CosRSUs and CosPSUs. The fair value of CosRSUs and CosPSUs is equivalent to the trading value of a common share of the Company on the valuation date.

Goodwill

Goodwill represents the excess of purchase price over fair value of net assets acquired, and is assessed for impairment annually at December 31 of each year. To test for impairment, goodwill is allocated to each of the Company’s CGUs, or groups of CGUs, that are expected to benefit from the acquisition and is tested as described in the Company’s impairment policy. The recoverable amount of an asset or a CGU is the greater of its value in use and its FVLCD.

Value in use is determined by estimating the present value of the future net cash flows expected to be derived from the continued use of the asset or CGU. FVLCD is based on available market information, where applicable. In the absence of such information, FVLCD is determined using discounted future net cash flows of proved plus probable reserves using forecast prices and costs. A downward revision in reserves estimates could result in the recognition of a goodwill impairment charge to net earnings.

These calculations require the use of estimates and assumptions and are subject to changes as new information becomes available including information on future commodity prices, expected production volumes, quantity of reserves and discount rates as well as future development and operating costs. Changes in assumptions used in determining the recoverable amount could affect the carrying value of the related assets and CGUs.

Derivative liabilities

Risk management contracts are initially recognized at fair value on the date a derivative contract is entered into and are remeasured at their fair value at each subsequent reporting date. The fair value of the risk management contract on initial recognition is normally the transaction price. Subsequent to initial recognition, the fair value are based on quoted market price where available from active markets, otherwise fair values are estimated based on market prices at the reporting date for similar assets or liabilities with similar terms and conditions.

Legal, environmental remediation and other contingent matters

In respect of these matters, the Company is required to determine both whether a loss is probable based on judgment and interpretation of laws and regulations and if such a loss can reasonably be estimated. When any such loss is determined, it is charged to net income. Management continually monitors known and potential contingent matters and makes appropriate provisions by charges to net income when warranted by circumstances.

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December 31, 2020

DIRECTORS

CORPORATE HEADQUARTERS

Wayne Foo Chairman of the Board

Parex Resources Inc.

2700, Eighth Avenue Place, West Tower 585 8 Avenue S.W., Calgary, Alberta, Canada T2P 1G1

Lisa Colnett

Sigmund Cornelius

Tel: 403-265-4800 Fax: 403-265-8216 E-mail: info@parexresources.com

Robert Engbloom

Bob MacDougall

OPERATING OFFICES

Glenn McNamara

Parex Resources Colombia Ltd. Sucursal Calle 113 No. 7-21, Of. 611, Edificio Teleport, Torre A, Bogotá, Colombia

Imad Mohsen

Carmen Sylvain

Tel: 571-629-1716 Fax: 571-629-1786

Paul Wright

OFFICERS & SENIOR EXECUTIVES

Imad Mohsen President and Chief Executive Officer

Eric Furlan Chief Operating Officer

AUDITORS

PricewaterhouseCoopers LLP Calgary, Alberta

LEGAL COUNSEL

Burnet, Duckworth & Palmer LLP Calgary, Alberta

TRANSFER AGENT AND REGISTRAR

Computershare Trust Company of Canada Calgary, Alberta

RESERVES EVALUATORS

GLJ Ltd. Calgary, Alberta

INVESTOR RELATIONS

Michael Kruchten Sr. Vice President, Capital Markets & Corporate Planning

Tel: 403-517-1733 Fax: 403-265-8216

Kenneth G. Pinsky Chief Financial Officer & Corporate Secretary

Daniel Ferreiro President, Parex Colombia & Country Manager

E-mail: Investor.Relations@parexresources.com Website: www.parexresources.com

Ryan Fowler Sr. Vice President, Exploration & Business Development

Michael Kruchten

Sr. Vice President, Capital Markets & Corporate Planning

Jeff Meunier

Vice President, New Ventures

Joshua Share

Sr. Vice President, Corporate Services

ABBREVIATIONS

Oil and Natural Gas Liquids

bbl(s) barrel(s) mbbls one thousand barrels bbl(s)/d barrels of oil per day BOE or boe barrel of oil equivalent, using the conversion factor of 6 Mcf: 1 bbl boe/d barrels of oil equivalent per day mcf thousand cubic feet mcf/d thousand cubic feet per day Other WTI West Texas Intermediate Brent Brent Ice Vasconia Vasconia Crude FFO Funds flow provided by operations

"BOEs" may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 mcf: 1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

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December 31, 2020