paramount resources ltd. november 2021 corporate presentation

November 2021

Corporate Presentation

Advisories

• In the interest of providing information regarding Paramount Resources Ltd. ("Paramount", "PRL" or the "Company") and its future plans and operations, this presentation contains certain forward-looking information and statements. The projections, estimates and forecasts contained in such forward-looking information and statements necessarily involve a number of assumptions and are subject to both known and unknown risks and uncertainties that may cause the Company's actual performance and financial results in future periods to differ materially from these projections, estimates and forecasts. The Advisories Appendix attached hereto lists some of the material assumptions, risks and uncertainties that these projections, estimates and forecasts are based on and are subject to. Readers are encouraged to carefully review the Advisories Appendix.

• All dollar amounts in this presentation are expressed in Canadian dollars, unless otherwise noted.

• Reserves and production information are presented in accordance with Canadian standards.

• The Advisories Appendix attached hereto contains additional information concerning the oil and gas measures and terms, reserves data and non-GAAP financial measures contained in this presentation.

• The forward-looking information and statements contained in this presentation are made effective as of November 3, 2021. Certain internally estimated play data contained in this presentation was prepared effective October 1, 2021. In each case, events or information subsequent to the applicable effective dates have not been incorporated.

• This presentation includes references to sales volumes of "natural gas", "condensate and oil", "NGLs", "Other NGLs" and "Liquids". "Natural gas" refers to conventional natural gas and shale gas combined. "Condensate and oil" refers to condensate, light and medium crude oil and tight oil combined. "NGLs" refers to condensate and Other NGLs combined. "Other NGLs" refers to ethane, propane and butane combined. "Liquids" refers to condensate and oil and Other NGLs combined. Readers are referred to the Product Type Information section of Advisories Appendix for more information about sales volumes by the specific product types of shale gas, conventional natural gas, NGLs, tight oil and light and medium crude oil.

2

83% 65%

70%

56% 59% 66%

6% 24%

25%

31% 34%

34%

9% 11%

13% 5%

-

$50

$100

$150

$200

$250

$300

$350

$400

$450

$500

$550

-

10

20

30

40

2020A 2021F 2022F 2023F

Pro

du

ctio

n (M

Bo

e/d

)

-

10

20

30

40

2020A 2021F 2022F 2023F

Pro

du

ctio

n (M

Bo

e/d

)

-

10

20

30

40

50

60

70

2020A 2021F 2022F 2023F

Pro

du

ctio

n (M

Bo

e/d

)

68,340

85,000

90,000

97,500

86,500

94,000

102,500

82,000

65,000

70,000

75,000

80,000

85,000

90,000

95,000

100,000

105,000

2020A 4Q21F 2021F 2022F 2023F

Shares Outstanding (MM) 135.0

Market Capitalization ($MM) (3) ~$2,900

Net Debt at Sep. 30, 2021 ($MM) (4) ~$580

Enterprise Value ($MM) ~$3,500

Monthly Dividend ($/share | Annualized Yield) (5) $0.06 | 3.4%

3

Corporate Overview

• Founded in 1976 (IPO’d in 1978)

• Significant insider ownership (~46%) (1)

• 1P Reserves: 311 MMBoe (46% liquids) (2)

• 2P Reserves: 632 MMBoe (47% liquids) (2)

• Q3 2021 Production: 82,150 Boe/d (45% liquids)

• Monthly dividend increased to $0.06/sh in November 2021

Focus Areas

Market Snapshot (TSX-POU)

(1) Consists of Common Shares held by directors, officers and other insiders. (2) See Advisories Appendix – Reserves Data. (3) 135.0MM shares at $21.48/share. (4) “Free cash flow”, “net debt” and “net debt to adjusted funds flow” are Non-GAAP Financial Measures. See Advisories Appendix – Non GAAP Financial Measures.

(5) Annualized yield is obtained by dividing 12 months of the stated monthly dividend by a share price of $21.48. (6) 2023 amounts are current expectations based on preliminary planning and current market conditions and are subject to change.

Natural Gas

Other NGLs

Condensate and Oil

Grande Prairie

*2021F, 2022F and 2023F production is based on midpoint of guidance

Wapiti/Karr Montney

Kaybob Montney/Duvernay

Willesden Green Duvernay

Paramount has significant land positions in the most liquids-rich areas of the prolific Montney and Duvernay plays

39% Liquids

46%

Liquids

(6)

44% Liquids

48%

Liquids

45% Liquids

Production (MBoe/d)(% Liquids)

~82(44%)

90-94

(46%)97.5-102.5

(48%)

CapEx ($MM) $285-$295 $500-$540 $475-$525

ARO ($MM) $25 $33 $40

Mid-point FCF ($MM) (4) ~$215 ~$455 ~$450

Net Debt/AFF (4) ~0.8x ~0.3x ~0.3x

Guidance Summary 2021F 2022F 2023F(6)

Kaybob and Central

2021F

(Midpoint)2022F

(Midpoint)

Grande Prairie

Kaybob

Central AB and Other

Corporate

Region

Sustaining Capital and Maintenance

Category

2023F

(Midpoint) (6)

Capital Outlook ($MM) Production Outlook Range (Boe/d)

Related to in year production growth

Related to subsequent year production growth

*

* Related to both in year and subsequent year production growth

-

$200

$400

$600

$800

$1,000

$1,200

$1,400

AFF CapEx & ARO FCF Uses AFF CapEx & ARO FCF Uses

2022F 2023F

$M

M

Free Cash Flow Generation and Debt Reduction

4

Paramount expects to achieve its net debt target of ~$300MM by Q3 2022

(1) See Advisories Appendix – Forward Looking Information for a breakdown of the pricing, cost and expenditure assumptions on which the forecast or illustrative free cash flow is based. (2) “Free cash flow”, “net debt”, “net debt to adjusted funds flow” and “adjusted funds flow" are Non-GAAP Financial Measures. See Advisories Appendix –

Non GAAP Financial Measures. (3) Based on year-end share count (includes ~5.3MM shares for conversion of convertible debentures into Common Shares at year-end 2021). Debt adjusted share count calculated as year-end share count plus (year-end net debt divided by current share price).

• ~110% free cash flow growth in 2022

• ~$165 million in proceeds from dispositions in 2021:

• ~$80 million from non-core asset sales in Q1

• ~$85 million from sale of Birch asset in Q3

2021F 2022F 2023F

Free Cash Flow Guidance ~$215 ~$455 ~$450

Midpoint of CapEx Guidance ~$290 ~$520 ~$500

ARO Guidance ~$25 ~$33 ~$40

Illustrative Adjusted Funds Flow (“AFF”) ~$530 ~$1,000 ~$1,000

Illustrative Net Debt* <$500 ~$300 ~$300

Illustrative Net Debt / AFF* ~0.8x ~0.3x ~0.3x

YoY Production and FCF Growth

Production per Share Growth (3) 15% 12% 9%

Production per Debt Adjusted Share Growth (3) 30% 17% 9%

• Paramount is prioritizing free cash flow as follows:

1) Net debt reduction to ~$300MM

2) Shareholder returns - Dividends and Share buybacks

3) Incremental growth - Organic development and Acquisitions

Illustrative Adjusted Funds Flow And Net Debt ($MM) (1)(2)

* Assumes that FCF is directed towards debt until achieving net debt of ~$300MM.

Illustrative AFF and FCF Estimates (1)(2)

• The Company has hedged ~23% of its midpoint 2022 forecast production to

provide greater FCF certainty

• Paramount estimates a WTI price of ~US$52.50/Bbl is required to fund 2022

CapEx, ARO, the dividend, and to achieve its net debt target

US$90/Bbl WTI

US$80/Bbl WTI

US$70/Bbl WTI

US$60/Bbl WTI

US$50/Bbl WTI

US$90/Bbl WTI

US$80/Bbl WTI

US$70/Bbl WTI

US$60/Bbl WTI

US$50/Bbl WTI

Debt

Repayment

Monthly Dividend

Remaining FCF

Monthly Dividend

Remaining FCF

2022F 2023F 2024F 2025F 2026F

Co

rpo

rate

FC

F ($

MM

)

Five-Year Outlook

5

Material free cash flow generation provides funding for incremental shareholder returns and growth

(1) Annual Capital Spending excludes land acquisitions and abandonment and reclamation activities. (2) The stated anticipated cumulative free cash flow is based on the following assumptions: (i) the stated annual capital expenditures and compound annual production growth; (ii) approximately $40 million in average annual abandonment

and reclamation costs, (iii) strip commodity prices and foreign exchange rates as at Oct. 22, 2021, and (iv) internal management estimates of future royalties, operating costs and transportation and processing costs.

• Paramount is providing an initial outlook through to the end of 2026 to highlight its

free cash flow and production growth potential

• The Company does not expect to pay Canadian income taxes within the next five

years at current strip prices

• Tax pools as of September 30, 2021 total ~$4.7 billion, including ~$3.5 billion

of immediately deductible pools

Illustrative Cumulative 2022-2026F Corporate Free Cash Flow

Potential (2)

Highlights of 5-Year Outlook

Annual Capital Spending (1) ~$500 MM

Compound Annual Production Growth Rate ~5%

Cumulative Free Cash Flow (2) >$2.7 Bn

Karr

Wapiti

Montney Oil

Willesden Green

Smoky

Ante CreekKaybobNorth

Kaybob South

-

50%

100%

150%

200%

250%

300%

350%

400%

- 2.0 4.0 6.0 8.0 10.0

6

Prudent Development of Inventory-Rich Opportunity SetParamount is allocating capital based on risk and return of opportunities while maintaining its balance sheet strength

• Significant inventory of opportunities across Paramount's

land base at various stages in the development lifecycle

• Free cash flows from properties in development stage

available for debt reduction and reinvestment

• Track record of opportunistic property dispositions

with a focus on maximizing value

• Measured and focused approach to development

• Current capital remains weighted towards Karr/Wapiti

• Owned and operated infrastructure in Kaybob allows

for near-term Duvernay development at Smoky and

Kaybob North

• Willesden Green Duvernay requires infrastructure

build-out to support material production growth

• Work ongoing to determine optimized

production plateau level

• Very attractive rate of return potential in the Duvernay,

where significant upside exists should DCET costs be

successfully reduced to Karr/Wapiti levels

(1) Paramount’s expectation as of October 1, 2021 of rate of return vs. total value assuming full field development on a relative basis.

Rat

e o

f R

etu

rn

Capital Allocation Long-TermNear-Term

Longer-term Assets:

• Deep Basin – Multi-Stacked Horizons

• Cavalier Energy – Heavy Oil

• Liard Basin – Dry Gas

• Horn River – Dry Gas

• MGM (Mackenzie Delta) – Dry Gas

Pla

y U

nd

erst

and

ing

Early Stage Appraisal Develop Harvest

Significant Asset Optionality & Value (1) Stage of Development

SmokyKaybob North

Dashed circles represent updated IRR/total value

assuming DC costs are scaled to those of Karr

Resthaven Sold in

2018 for $340MM

Musreau Sold in 2016

for $2.1Bn

West Central Sold

in 2019 for $55MM

Birch Sold in July

2021 for $85MM

Kaybob North

Willesden Green

Kaybob South

Ante Creek

Smoky

Wapiti

Karr

Montney Oil

7

Karr Activity and ProductionParamount’s flagship asset at Karr reached targeted plateau production of ~40,000 Boe/d in March 2021

• Actively began development in 2016 with 74 wells brought onstream to the end of October 2021

• 2022 activities include 14 drills, 16 completions and 16 wells to be brought onstream

• Maintaining targeted plateau production of ~40,000 Boe/d will require ~12-16 wells (1) per year

• At plateau production, annual asset level free cash flow would be $340 million to $365 million (2)

• Management high-graded undeveloped location count of 224 wells (Middle Montney development)

• ~63% assigned reserves as at December 31, 2020 (3)

• Supports 20+ years of production at plateau with Upper and Lower Montney included

Quarterly Production (Boe/d) and Activity Outlook

(1) Early years will require more wells to maintain plateau production, given higher initial declines. Over time, less wells are required. (2) “Asset level free cash flow” is a Non-GAAP financial measure. See “Non-GAAP Financial Measures” in the Advisories section. Stated amounts are illustrative assuming netbacks equal to Karr 2021 YTD per-unit netbacks of

$30.77/Boe, and 12 to 16 new wells per year at an average DCET cost of $7.1 million per well, excluding the cost of any potential incremental infrastructure requirements in the future. (3) See Advisories Appendix – Undeveloped Locations.

40,000 39,000 39,000

42,000 43,000 43,000

33,230

38,679 39,878

30,000

35,000

40,000

45,000

1Q21A 2Q21A 3Q21A 4Q21F 2022F 2023F


• Brought onstream 6

wells at the 3-10 pad

• Drilled 3 wells at the 4-

28 pad and 5 wells at

the 7-18 pad

• Commenced drilling of 5

wells at the 5-16 East

pad



• Finished completion

operations of 5 wells at

the 7-18 pad

• 7 day, 50% sales

volume curtailment at 6-

18 facility



• Commenced drilling of 7


(only 7 to be drilled in

2021)

• Commenced completion

operations on 5 wells on

the 5-16 East pad in Q3

• Finished completions,

tie-in and brought on

production 5 wells at the

5-16 East pad in late

October

52% Liquids 51% Liquids

55% Liquids

54% Liquids52% Liquids 49% Liquids

• Complete and bring

onstream 7 of 12 wells

on the 16-17 pad in

2Q22

• Drill, complete, tie-in

and bring onstream the

remaining 5 wells on the

16-17 pad

• Drill, complete, tie-in

and bring onstream the

4 well 1-2N pad

• Commence drilling of

the 5 well 4-2 pad

• Maintain target plateau

production by bringing

onstream ~12-16

wells(1)

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Producing Days

Cumulative Boe – Karr Wells

8

Karr Performance and Recent HighlightsParamount’s Montney wells at Karr continue to perform strongly, resulting in improved deliverability

(1) Production measured at the wellhead. Natural gas sales volumes are lower by approximately 6 percent and liquids sales volumes are lower by approximately 6 percent due to shrinkage. The production rates and volumes stated are over a short period of time and, therefore, are not necessarily indicative of average daily production, long-

term performance or of ultimate recovery from the wells. CGR means the condensate to gas ratio calculated by dividing wellhead NGLs volumes by wellhead natural gas volumes. See Advisories Appendix – Oil and Gas Measures and Definitions. (2) Based on actuals to September 2021 and forecasts thereafter. (3) Production measured

at the wellhead. Natural gas sales volumes are lower by approximately 6 percent and liquids sales volumes are lower by approximately 6 percent due to shrinkage. (4) Per well data based on management estimates and price deck. See Advisories Appendix – Play Data. (5) See Advisories Appendix – Oil and Gas Measures and Definitions.

Cumulative NGLs – Karr Wells• Highly productive liquids-rich wells drive industry-

leading half-cycle economics

• Estimated per well sales volumes now ~1.7

MMBoe (up from ~1.2 MMBoe) on lower DCET

• Implied capital efficiency of ~$5,500/Boe/d (4)

• PDP finding and development costs were

$8.96/Boe in the Grande Prairie Region in 2020 (5)

• Results in a recycle ratio of 3.4x when using

Karr’s 2021 YTD operating netback of

$30.77/Boe

IP 365 (Boe/d) 1,297

IP 365 CGR (Bbl/MMcf) 169

Sales Volume (MBoe) 1,677

Average CGR (Bbl/MMcf) 97

Sales Gas Volume (Bcf) 5.9

Sales Condensate (MBbl) 560

DCET ($MM) $7.1

Play Data – 3,000m Avg. Lateral Length (4)

Type Curve (3)

Type Curve (3)

Recent Highlights

• The five-well 5-16 East pad was brought onstream in late October

• Preliminary DCET costs averaged $6.3MM/well

• Brought onstream five wells on the 7-18 pad in late July

• DCET costs averaged $6.1MM/well

• Averaged 2,137 Boe/d (6.4 MMcf/d of shale gas and 1,076

Bbl/d of NGLs) of peak 30-day wellhead production per well

with an average CGR of 169 Bbl/MMcf (1)

• Projected payout of approximately 5 months after coming

onstream (2)

• The six-well 3-10 pad that was brought onstream in February

2021 continues to outperform internal type well projections

resulting in all wells paying out in just four months

• Achieved an operating netback of $35.27/Boe in the third quarter

of 2021, representing a new record for the Karr asset

• Operating expenses were $9.03/Boe in the third quarter, lower

than the targeted $10.00/Boe at plateau production

$0

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$MM

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9

Karr Performance

Karr Well Performance by Program

* Well 22 DCET significantly higher due to failed liner and subsequent casing repair.

Lifetime Netback (Actual + Forecast Using Oct. 1, 2021 Price Deck) divided by DCET by Well (Right Axis)

Actual Netback to Aug. 31, 2021 (1) (Left Axis)

Forecast Remaining Netback (Per Dec. 31, 2020 McDaniel Report) (2) (Left Axis)

Average DCET by Program (Left Axis)

(1) See Advisories Appendix – Non GAAP Measures. (2) See Advisories Appendix – Reserves Data. Amounts represent undiscounted forecast proved plus probable netback over the remaining life of each well as included in the McDaniel Report. (3) Amounts represent undiscounted forecast total proved plus probable netback over the remaining

life of each well as calculated by management consistent with the forecasts, assumptions and methodology in the McDaniel Report but utilizing an updated price forecast that is the average of the Oct. 1, 2021 price forecasts for McDaniel and GLJ Petroleum Consultants Ltd. and the Sep. 30, 2021 price forecast of Sproule Associates Ltd.

2016/17 Program2.4x Avg/Well

2019 Program2.7x Avg/Well



$13.3 MM $11.9 MM $12.3 MM$7.8 MM

Wells exhibit strong returns and quick payouts

$6.5 MM


Forecast Remaining Netback (Using Oct. 1, 2021 Price Deck) (3) (Left Axis)

10

Wapiti Activity and ProductionParamount has accelerated 2021 development to advance the next major phase of growth at Wapiti

• Development commenced in 2018 with 36 wells brought onstream to the end of October 2021

• 2022 activity includes 32 drills, 25 completions and 22 wells to be brought onstream

• Takeaway capacity in place to support Montney production growth

• Targeting plateau production of ~30,000 Boe/d in 2023

• Management full field development location count of 221 wells

• ~66% assigned reserves as at December 31, 2020 (1)

• Supports 20+ years of production at plateau


(1) See Advisories Appendix – Undeveloped Locations.

• Completed the drilling of

remaining 4 wells on the

7-well 6-4 pad

• Completed 7 wells on

the 6-4 pad

• Commenced drilling 7

wells on the 9-22 pad


wells on the 6-4 pad

• 10 day scheduled

facility outage

• Drilled one tenure well

• Complete and bring

onstream 4 of 7 wells

on the 9-22 pad

• Commence drilling of

the 8 well 8-22 pad (2 to

be drilled in 2021)

12,000

19,000

26,000

16,000

22,000

29,000

14,107

10,604

14,651

5,000

10,000

15,000

20,000

25,000

30,000

1Q21A 2Q21A 3Q21A 4Q21F 2022F 2023F

59% Liquids60% Liquids

59% Liquids

57% Liquids

62% Liquids 62% Liquids

• Bring onstream the

remaining 3 wells on

the 9-22 pad and 1 well

on the 10-22 pad

• Finish the drilling of the

8-22 pad, CET and

bring onstream all 8

wells

• DCET 2x 8 well pads

and bring onstream 10

wells

• Drill the 8 well 8-15 pad

• Continue to bring new

wells onstream in

support of reaching the

targeted 30,000 Boe/d

in the year

0

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0 200 400 600 800 1000

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Producing Days

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0 200 400 600 800 1000

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oe

Producing Days

Recent Highlights

• In May, Paramount expanded its capital program to bring forward

activities by approximately 6 months into the second half of 2021

• More recently, the Company also accelerated additional drilling

activity into late 2021

Plans include:

• DCET and bring on production seven new Montney wells at

the 9-22 pad

• Commence drilling operations on the eight-well 8-22 pad in

late 2021

• Install associated infrastructure

Benefits:

• Higher 2021 exit production and 2022 production

• Improved 2023+ asset level free cash flow profile

• The seven well 6-4 pad was brought onstream in early July

• DCET costs averaged $6.9 million per well

• Averaged 1,292 Boe/d (3.0 MMcf/d of shale gas and 794 Bbl/d

of NGLs) of peak 30-day wellhead production per well with an

average CGR of 266 Bbl/MMcf (1)

11

Wapiti Performance and Recent HighlightsLower DCET costs and the implementation of an optimized well completion have further enhanced Wapiti economics

• Implied capital efficiency of ~$8,200/Boe/d using

the Company’s assumptions (3)

• PDP finding and development costs were

$8.96/Boe in the Grande Prairie Region in 2020 (4)

• Results in a recycle ratio of 3.5x when using

Wapiti’s 2021 YTD operating netback of

$31.60/Boe

IP 365 (Boe/d) 856


Sales Volume (MBoe) 780




DCET ($MM) $7.0


(1) Production measured at the wellhead. Natural gas sales volumes are lower by approximately 13 percent and liquids sales volumes are lower by approximately 1 percent due to shrinkage. The production rates and volumes stated are over a short period of time and, therefore, are not necessarily indicative of average daily production, long-

term performance or of ultimate recovery from the wells. CGR means the condensate to gas ratio calculated by dividing wellhead NGLs volumes by wellhead natural gas volumes. See Advisories Appendix – Oil and Gas Measures and Definitions. (2) Production measured at the wellhead. Natural gas sales volumes are lower by

approximately 13 percent and wellhead liquids sales volumes are lower by approximately 1 percent due to shrinkage, under normalized operations. (3) Per well data based on management estimates and price deck. See Advisories Appendix – Play Data. (4) See Advisories Appendix – Oil and Gas Measures and Definitions.

Cumulative Boe – Wapiti Wells

Cumulative NGLs – Wapiti Wells

Type Curve (2)

Type Curve (2)

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$MM

0.0x

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12

Wapiti Performance

Wapiti Well Performance by Program


$11.3 MM


$9.6 MM


$7.5 MM

With recent well cost improvements, Wapiti wells are generating strong returns on invested capital

Lifetime Netback (Actual + Forecast Using Oct. 1, 2021 Price Deck) divided by DCET by Well (Right Axis)

Actual Netback to Aug. 31, 2021 (1) (Left Axis)

Forecast Remaining Netback (Per Dec. 31, 2020 McDaniel Report) (2) (Left Axis)

Average DCET by Program (Left Axis)

(1) See Advisories Appendix – Non GAAP Measures. (2) See Advisories Appendix – Reserves Data. Amounts represent undiscounted forecast proved plus probable netback over the remaining life of each well as included in the McDaniel Report. (3) Amounts represent undiscounted forecast total proved plus probable netback over the remaining

life of each well as calculated by management consistent with the forecasts, assumptions and methodology in the McDaniel Report but utilizing an updated price forecast that is the average of the Oct. 1, 2021 price forecasts for McDaniel and GLJ Petroleum Consultants Ltd. and the Sep. 30, 2021 price forecast of Sproule Associates Ltd.

Forecast Remaining Netback (Using Oct. 1, 2021 Price Deck) (3) (Left Axis)


$6.9 MM

$6.0 MM/well

$5.9 MM/well

$3.9 MM/well

$3.2 MM/well

$200

$350

$500

$650

$800

-

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$7.0

$8.0

2018 2019 2020 2021

$/to

nn

e$M

M

Total Completion Cost (LHS)

Completion Cost / Tonne of Proppant (RHS)

0

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Dep

th (M

eter

s)

Days from Spud

13

Grande Prairie Capital EfficienciesParamount’s focus on continuous improvement has resulted in consistently lower well costs at Karr and Wapiti

Grande Prairie Region Average Drilling Days Grande Prairie Region Average Completion Costs

• Paramount expects to realize capital cost efficiencies in its Duvernay plays at Kaybob and Willesden Green, similar to the gains achieved over the past 18 months at Karr and Wapiti, as it commences pad development and captures economies of scale

01,0002,0003,0004,0005,0006,000

0 5 10 15 20 25 30 35 40D

epth

(Met

ers)

Days from Spud

Pacesetter2021202020192018

14

Kaybob DuvernayParamount controls a material and increasingly de-risked position in the Kaybob Duvernay

Kaybob Duvernay Plans:

• With Karr at plateau production and Wapiti on its way to achieving plateau

production in 2023, the Company is now in a position to start methodically

developing its Kaybob Duvernay assets

• Development of the Duvernay at Kaybob Smoky and Kaybob North will

commence in 2022

Kaybob Duvernay Overview:

• Large portfolio of resource plays in the Kaybob Region

• ~200,000 net acres of Duvernay rights

• ~272,000 net acres of Montney rights

• Two recent large transactions totaling over $1.2 billion in lands directly adjacent to

the Company’s Kaybob North Duvernay asset base

• Increased activity by purchasers expected to continue to de-risk

Paramount’s lands

• Ownership in critical facilities and pipeline infrastructure including:

• 8-9 Gas Plant

• 6-16 Smoky Gas Plant

• 12-10 Oil Battery

• Paramount owns and operates a crude oil terminal in the Kaybob area that was first

put into service in 2019

• Netback enhancing for the Kaybob Region, capturing incremental value in

price differentials with capacity to handle future growth

15

Kaybob Smoky Duvernay OverviewA competitive cost structure at Smoky coupled with targeted capital efficiencies are expected to drive FCF growth

• The Kaybob Smoky Duvernay asset has been de-risked with competitor wells surrounding

Paramount’s lands

• Plans for 2022 include the expansion of the Company’s 100% owned and operated 6-16

facility that would increase gas processing capacity from 6.5 MMcf/d to 12 MMcf/d and

increase condensate processing and handling capacity from 2,000 Bbl/d to 5,000 Bbl/d

• Plans also include the drilling, completion, tie-in and bringing onstream of the four-well 10-35

pad in the second half of 2022

• Targeting plateau production of ~6,000 Boe/d by 2024

• ~49 full field development locations (~53% assigned reserves as at December 31, 2020) (1)

(1) See Advisories Appendix – Undeveloped Locations. (2) Per well data based on management estimates and price deck. See Advisories Appendix – Play Data

IP 365 (Boe/d) 680






DCET ($MM) $9.0

Play Data – 2,800m Avg. Lateral Length (2)• Implied capital efficiency of

~$13,200/Boe/d using the Company’s

assumptions (2)

• Paramount expects to realize capital

cost efficiencies at Smoky Duvernay

similar to those achieved over the past

two years at Karr and Wapiti

16

Kaybob North Duvernay OverviewThe next wedge of production growth for Paramount will come from the Kaybob North Duvernay play

• Competitor activity continues to de-risk Paramount land

• Activity has increased in 2021 and expect this to continue into 2022+

• In 2022, the Company plans to drill the remaining two wells at the three-well 12-21 pad and

bring all three wells onstream in late 2022

• Targeting plateau production of ~12,000 Boe/d by 2026

• ~83 full field development locations (1) that factors in:

• ~600m inter-well spacing, up from 320m last year; and

• Longer lateral length of 4,200m, up from 3,000m last year

• Work continues to determine optimal inter-well spacing

IP 365 (Boe/d) 668






DCET ($MM) $11.2


(1) See Advisories Appendix – Undeveloped Locations. (2) Per well data based on management estimates and price deck. See Advisories Appendix – Play Data

• Implied capital efficiency of

~$16,800/Boe/d using the Company’s

assumptions (2)

• Paramount expects to realize capital

cost efficiencies in the Kaybob North

Duvernay similar to those achieved

over the past two years at Karr and

Wapiti

17

Other Duvernay and Montney Assets at KaybobAssets have significant upside with a great deal of running room. Limited capital is currently being deployed

Kaybob South Duvernay Kaybob North Montney Oil

• Enhanced oil recovery pilot project will be expanded in 2022 to continue to assess the viability of implementation across the entire field


• In 2019, the Company brought on production 5 (2.5 net) wells on the 2-28 pad

• ~64 (gross) full field development locations (~47% assigned reserves as at December 31, 2020) (1)

• Plans for 2022 include the completion, tie-in and bringing onstream of one tenure well in the second half of the year


Ante Creek Montney Oil

(1) See Advisories Appendix – Undeveloped Locations.

0

50

100

150

200

0 10 20 30 40 50 60

Cu

mu

lati

ve O

il (M

Bb

l)

Normalized Time Months

18

Central Willesden Green Duvernay OverviewMaterial, contiguous Duvernay land position at Willesden Green with strong results from most recent wells

• Early production rates at the two-well 4-7 pad brought onstream in July are extremely encouraging

• Despite being restricted by facility constraints, average gross peak 30-day production per well at

the 4-7 pad was 1,498 Boe/d (3.3 MMcf/d of shale gas and 948 Bbl/d of NGLs) with an average

CGR of 287 Bbl/MMcf (1)

• Planned activities in 2022 include the addition of water infrastructure and FEED studies for future facility

expansion that will benefit Duvernay development in the Willesden Green area


(1) Production measured at the wellhead. Natural gas sales volumes are lower by approximately 4 percent and liquids sales volumes are lower by approximately 9 percent due to shrinkage. The production rates and volumes stated are over a short period of time and, therefore, are not necessarily indicative of average

daily production, long-term performance or of ultimate recovery from the wells. CGR means the condensate to gas ratio calculated by dividing wellhead NGLs volumes by wellhead natural gas volumes. See Advisories Appendix - Oil and Gas Measures and Definitions. (2) See Advisories Appendix – Undeveloped

Locations. (3) Per well data based on management estimates and price deck. See Advisories Appendix – Play Data.

IP 365 (Boe/d) 770






DCET ($MM) $10.0

Play Data at 4,000m Avg. Lateral Length (3)

One well drilled to a lateral length of ~4,000m and

a total MD of ~7,400m (longest horizontal well

drilled in the Company’s history)

Paramount’s 5-29 well is one of

the best performing Duvernay oil

wells in Willesden Green to date

Oil – All Industry WG Duvernay Oil Wells

• Implied capital efficiency of ~$13,000/Boe/d using the Company’s assumptions (3)

• The company expects capital efficiencies to improve over time as it develops the play

0.0000

0.0100

0.0200

0.0300

-

250,000

500,000

750,000

2019 2020

tCO2e/Boe

tCO2e

Scope 1 Scope 2 Intesity

Environmental, Social and Governance (“ESG”)

19

Paramount prides itself in delivering value to all stakeholders in a responsible manner

• Reduced year-over-year Scope 1 & 2 absolute

emissions by 17% in 2020

• Completed the replacement of high vent controllers,

reducing GHG emissions by an estimated 60,000

tCO2e annually after accounting for recent

dispositions

• Bi-fuel drilling rigs contributed to a ~56% reduction

in per well diesel consumption since 2018

• New Karr wastewater infrastructure expected to

reduce GHG emissions by ~13,500 tCO2e annually

• Foster a safety conscious culture with written

policies and procedures to protect the health and

safety of those involved with and affected by our

operations

• Support a wide range of community and charitable

organizations both financially and through

volunteer hours

• Committed to creating and maintaining an

environment that respects diverse traditions,

heritages and experiences

• 75% Independent Board Members; Independent Lead

Director

• Fully independent Audit, Compensation, Corporate

Governance, and Reserves Committees

• Environmental, Health and Safety Committee of the

Board of Directors and senior management provide

oversight in ESG related matters

Environmental Social

• Minimum shareholding requirements for directors

• Officers and directors prohibited from hedging

Paramount securities

• Loans to officers and directors prohibited

• Code of Ethics and Code of Business Conduct

• Anonymous Whistleblower Policy and portal

Governance

0.4%Scope 1 + 2

emissions

intensity

17%Scope 1 + 2

absolute

emissions

Scope 1 Scope 2 Intensity

Paramount’s ESG report can be found on our website (including performance tables)

Emission Reduction Initiative

20

Paramount is evaluating a zero/ultra-low emissions power generation, CCUS and EOR project

O2Generator

Zero/Ultra-low

Emissions

Commercial

Power Sales

Zero/ultra-low

emissions

onsite power

generation

Oxy-Combustion

Turbine

Steam

Condenser &

Separator

Natural

Gas

Pure Water

CO2

Compressed CO2 is

injected into existing oil

fields as part of an EOR

scheme

Excess water is

condensed and used in

the Company’s future

completion operations

• Paramount has engaged an outside engineering firm and is working with

Clean Energy Systems Inc. (“CES”) to assess the opportunity for an ultra-

low emission upgrade to one of the Company’s facilities

• Paramount has held an indirect ownership in CES for over a decade

through its investment in Paxton Corporation

• Benefits include:

• Zero/ultra-low greenhouse gas emission power generation for use at the

facility with excess sold to the grid

• Eliminates effectively all Scope 1 and Scope 2 emissions associated with

the facility

• CO2 to be captured, compressed and injected into a nearby 100%

Paramount owned and operated oil field, increasing the ultimate

recovery and extending the life of the asset, improving the return

proposition of the total project

• Excess water from condensed process steam to be used in the

Company’s future developments, minimizing the need to procure fresh

water from streams and rivers

58% 17%

6%

11% 8%

Credit Facility and Risk Management

21

Paramount has an active market risk diversification and risk management strategy

The Company has undertaken an active hedging program to provide greater free cash

flow certainty

• ~23% of forecast midpoint 2022 production is hedged

• ~15,500 Bbl/d of oil and ~36 MMcf/d of natural gas hedged in 2022

• Well-diversified natural gas portfolio with sales priced at Alberta, California, Chicago, Ventura and Eastern

Canada markets

AECO

Dawn

Malin

US Midwest

AECO Fixed-Price

Physicals

2022F Gas Diversification

Credit Facility and Convertible Debentures

• Paramount has a $900 million financial-covenant based revolving bank credit facility (June 2024 maturity date)

• Expandable to $1.0 billion with accordion feature (subject to incremental lender commitments)

• ~$490 million drawn at September 30, 2021

• The Company has delivered notices to redeem all $35 million of its 7.5% senior unsecured convertible debentures, effective December 3, 2021

• All holders are expected to exercise their right to convert resulting in ~5.3 million Common Shares being issued

Strategic and Long-Term Investments

22

Paramount is unique in that it holds strategic positions in a number of public and private entities

Summary of Investments & Other Assets

Investments in Public Companies (1) ~$230 million

Investments in Private Companies (2) ~$70 million

Drilling Rigs – Book Value (2) ~$60 million

Undeveloped Land Not quantified

Total ~$360 million

MGM Energy Corp.

Wholly owned by Paramount

Mackenzie Delta

• ~181,912 (29,342 net) acres

• Significant Discoveries at Umiak,

Qavvik, Olivier, Langley and Ellice

Central Mackenzie

• 301,055 (177,544 net) acres

• Significant Discovery at Nogha, Colville

Lake

• Significant Discovery of shale oil at East

Mackay

Fox Drilling


• Four triple-sized walking rigs

• Three conventional triple-sized rigs

Liard Basin

Cavalier Energy Inc.


• Cavalier Energy’s lands are prospective for in-

situ thermal oil recovery and heavy oil

• 1.354 million gross acres of land located

primarily in the Athabasca and Peace River

regions of Alberta

• ~430 gross sections with Clearwater and

Bluesky potential

Horn River BasinMuskwa Shale Play

• Prospective feedstock for west coast LNG

• Paramount holds ~34,049 (18,341 net) acres

• 65 gross (32.5 net) drilled and producing wells

(1) Market value of public companies as at Sep. 30, 2021 (includes 39.8 million shares of NuVista Energy Ltd. @ $5.14/share). (2) Carrying value as at Sep. 30, 2021. For further details refer to Paramount’s consolidated financial statements as at Sep. 30, 2021.

Besa River Shale Play

• Prospective feedstock for west coast LNG

• Paramount holds ~135 net sections

• Drilled 4 (4.0 net) wells for play delineation and

land retention

SultranParamount holds a ~16% ownership

• Supply chain and logistics solutions for

bulk commodities

• Wholly-owned BC terminal facilities

(Pacific Coast Terminals Co. Ltd.)

Other Long Term Resources

Liard Basin natural gas

Mackenzie Delta natural gas

Cavalier Energy thermal oil and Clearwater potential

• Minimal ongoing holding costs, lease rental only

• Maintain flexibility to determine development timeline

• Prospective for future free cash flow through joint ventures, farm outs or dispositions

Paramount Investment Attributes

• 40+ year history of responsible energy development and environmental stewardship

• Extensive portfolio of liquids-rich resource plays in the Montney and Duvernay

• Risk-adjusted returns-focused capital allocation strategy supported by rigorous full-cycle analysis

• Significant and sustainable improvement in both capital and operating cost structure

• Forecast to generate meaningful free cash flow

• Not expected to pay Canadian income taxes within the next five years at current strip prices

• Strong liquidity position with expected year-end 2021F net debt to adjusted funds flow of ~0.8x (1)

• Stakeholder-aligned management and board with significant insider ownership

• Incremental shareholder returns with the implementation of an inaugural monthly $0.02/share dividend in July 2021 and

subsequent tripling in November to $0.06/share

23

Paramount offers a unique investment proposition

(1) “Net debt”, “adjusted funds flow” and “net debt to adjusted funds flow” are Non-GAAP Financial Measures. See Advisories Appendix – Non GAAP Financial Measures.

Appendix

DCET Costs Total

Wellhead

NGLs

Wellhead Shale

Gas CGR (3)

Total

Wellhead

NGLs

Wellhead

Shale Gas CGR (3)

($MM) (Boe/d) (Bbl/d) (MMcf/d) (Bbl/MMcf) (MBoe) (MBbl) (Bcf) (Bbl/MMcf)

7-18 Pad

00/01-06-066-04W6/0 2,359 1,212 6.9 176 208 113 565 201 105

00/02-06-066-04W6/0 2,246 1,038 7.3 143 188 93 566 165 106

02/01-06-066-04W6/0 2,574 1,314 7.6 174 226 127 594 214 105

02/02-06-066-04W6/0 2,490 1,230 7.6 163 191 97 563 172 106

03/03-06-066-04W6/0 1,018 585 2.6 225 88 49 235 207 100

Avg. per well $6.1 2,137 1,076 6.4 169 180 96 505 189 104

4-28 Pad

00/08-27-066-04W6/0 1,482 882 3.6 245 201 112 530 212 192

00/09-27-066-04W6/0 1,019 524 3.0 176 164 87 464 187 194

02/16-32-066-04W6/2 1,384 777 3.6 213 227 117 657 178 196

Avg. per well $6.9 1,295 728 3.4 214 197 105 550 191 194

3-10 Pad

00/01-34-065-05W6/0 2,139 962 7.1 136 464 234 1,378 170 257

00/02-34-065-05W6/0 2,527 1,513 6.1 249 521 284 1,418 201 266

00/03-34-065-05W6/0 2,103 1,091 6.1 180 493 237 1,531 155 268

02/01-34-065-05W6/0 2,095 910 7.1 128 493 247 1,478 167 262

02/02-34-065-05W6/0 2,025 995 6.2 161 480 226 1,522 149 268

02/03-34-065-05W6/0 2,095 1,207 5.3 226 492 243 1,495 162 265

Avg. per well $6.6 2,164 1,113 6.3 176 491 245 1,470 167 264

2020 Wells

15 wells (Avg. per well) $7.8 1,548 907 3.8 236 400 205 1,166 176 404

2019 Wells

8 wells (Avg. per well) $12.3 1,825 1,262 3.4 373 543 333 1,262 264 727

2018 Wells

5 wells (Avg. per well) $11.9 1,760 1,051 4.3 247 701 367 2,005 183 853

2016/2017 Wells

27 wells (Avg. per well) $13.3 1,969 1,171 4.8 245 841 418 2,546 164 1,201

Days on

Production

Peak 30-Day (1)

Cumulative (2)

25

AppendixThe following summarizes the performance of the wells at Karr

(1) Peak 30-Day is the highest daily average production rate over a 30-day consecutive period for each well, measured at the wellhead. Natural gas sales volumes are approximately 6 percent lower and NGLs sales volumes are approximately 6 percent lower due to shrinkage. Excludes days when the wells did not produce. The production rates

and volumes shown are 30-day peak rates over a short period of time and, therefore, are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells. These wells were produced at restricted rates from time-to-time due to facility and gathering system constraints. See ʺOil and Gas Measures

and Definitionsʺ in the Advisories. (2) Cumulative is the aggregate production measured at the wellhead to October 31, 2021. Natural gas sales volumes are approximately 6 percent lower and NGLs sales volumes are approximately 6 percent lower due to shrinkage. These wells were produced at restricted rates from time-to-time due to facility

and gathering system constraints. The production rates and volumes shown are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells. (3) CGR means condensate to gas ratio calculated by dividing wellhead NGLs by wellhead natural gas volumes.

*Paramount is a single stream reporter, and as such, all public production data represents recombined gas.

DCET Costs Total Wellhead NGLs

Wellhead

Shale Gas CGR (3)

Total

Wellhead

NGLs

Wellhead

Shale Gas CGR (3)

($MM) (Boe/d) (Bbl/d) (MMcf/d) (Bbl/MMcf) (MBoe) (MBbl) (Bcf) (Bbl/MMcf)

6-4 Pad

02/06-16-068-06W6/0 1,040 744 1.8 418 91 64 167 382 103

03/05-16-068-06W6/0 1,284 879 2.4 362 106 71 212 333 94

03/06-16-068-06W6/0 1,336 952 2.3 413 99 68 185 367 101

00/11-28-067-06W6/0 1,105 680 2.6 266 96 53 256 208 106

00/12-28-067-06W6/0 1,413 771 3.9 200 120 67 319 210 100

02/11-28-067-06W6/0 1,268 695 3.4 202 122 67 326 207 106

02/12-28-067-06W6/0 1,598 837 4.6 183 131 71 360 197 93

Avg. per well $6.9 1,292 794 3.0 266 109 66 261 253 100

5-3 West Pad

00/07-16-068-06W6/0 1,124 798 2.0 407 260 176 506 347 318

00/10-28-067-06W6/0 1,274 814 2.8 295 253 144 652 221 309

02/07-16-068-06W6/0 1,195 838 2.1 391 240 167 434 386 291

02/10-28-067-06W6/0 1,248 790 2.7 288 221 128 558 229 279

03/09-28-067-06W6/0 1,105 733 2.2 329 258 152 637 239 329

Avg. per well $7.5 1,189 795 2.4 336 246 153 557 275 305

5-3 East Pad

03/11-27-067-06W6/0 2,013 1,241 4.6 268 388 203 1,114 182 631

04/06-15-068-06W6/0 1,567 1,053 3.1 341 317 190 763 249 593

02/09-28-067-06W6/0 1,694 1,055 3.8 275 306 171 813 210 507

02/11-27-067-06W6/0 1,931 1,209 4.3 279 389 220 1,013 217 615

00/12-27-067-06W6/0 1,315 868 2.7 323 288 158 779 203 551

02/12-27-067-06W6/0 1,843 1,191 3.9 304 360 189 1,029 183 555

00/09-28-067-06W6/0 1,526 1,012 3.1 328 322 178 861 207 524

03/06-15-068-06W6/0 1,312 918 2.4 389 322 197 748 263 559

00/05-15-068-06W6/0 1,287 895 2.3 381 247 163 503 323 512

02/05-15-068-06W6/0 1,484 997 2.9 342 319 195 742 263 541

00/08-16-068-06W6/0 1,339 878 2.8 318 323 206 700 294 541

02/08-16-068-06W6/0 1,743 1,214 3.2 382 285 196 532 369 450

Avg. per well $9.6 1,588 1,044 3.3 320 322 189 800 236 548

9-3 Pad

11 wells (Avg. per well) $11.1 1,051 722 2.0 366 368 220 888 248 778

Peak 30-Day (1)

Cumulative (2)

Days on

Production

26

AppendixThe following summarizes the performance of the wells at Wapiti

(1) Peak 30-Day is the highest daily average production rate over a 30-day consecutive period for each well, measured at the wellhead. Natural gas sales volumes are approximately 13 percent lower and NGLs sales volumes are approximately 1 percent lower due to shrinkage. Excludes days when the wells did not produce. The production rates

and volumes shown are 30-day peak rates over a short period of time and, therefore, are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells. These wells were produced at restricted rates from time-to-time due to facility and gathering system constraints. See ʺOil and Gas Measures

and Definitionsʺ in the Advisories. (2) Cumulative is the aggregate production measured at the wellhead to October 31, 2021. Natural gas sales volumes are approximately 13 percent lower and NGLs sales volumes are approximately 1 percent lower due to shrinkage. These wells were produced at restricted rates from time-to-time due to facility

and gathering system constraints. The production rates and volumes shown are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells. (3) CGR means condensate to gas ratio calculated by dividing wellhead NGLs by wellhead natural gas volumes.

*Paramount is a single stream reporter, and as such, all public production data represents recombined gas.

Advisories

Advisories

28

Forward-Looking Information

Certain statements in this presentation constitute forward-looking information under applicable securities legislation. Forward-looking information typically contains statements with words such as "anticipate", "believe", "estimate", "will", "expect", "plan", "intend", "propose", or similar words

suggesting future outcomes or an outlook.

Forward-looking information in this presentation includes, but is not limited to: (i) the payment of future dividends under the Company’s monthly dividend program; (ii) forecast sales volumes in 2021 and 2022 and certain periods therein; (iii) planned capital expenditures in 2021 and 2022 and

the allocation thereof; (iv) planned abandonment and reclamation activities and expenditures; (v) forecast free cash flow in 2021 and 2022; (vi) forecast net debt to adjusted funds flow in 2021; (vii) illustrative adjusted funds flow in 2021, 2022 and 2023; (viii) illustrative net debt in 2021, 2022

and 2023; (ix) illustrative net debt to adjusted funds flow in 2022 and 2023; (x) preliminary anticipated capital expenditures in 2023 and the resulting expected 2023 average sales volumes and free cash flow; (xi) illustrative production per share and debt adjusted share growth and free cash

flow growth: (xii) the expected meeting by the Company of its $300 million net debt target by the end of the third quarter of 2022; (xiii) the Company’s priorities for the allocation of free cash flow; (xiv) the Company’s five-year outlook for capital spending, annual production growth rate and

cumulative free cash flow; (xv) the Company’s expectation that it will not be required to pay Canadian income taxes within the next five years; (xvi) potential rates of return for the Company’s properties; (xvii) the number of wells per year required to maintain plateau production at Karr; (xviii)

illustrative asset level free cash flow potential at Karr; (xix) undeveloped locations for certain properties and the years of plateau production supported by undeveloped locations at Karr and Wapiti; (xx) the targeted date for achieving plateau production at Wapiti; (xxi) play data, anticipated well

performance and forecast netback; (xxii) planned exploration, development and production activities, including the expected timing of completing and bringing new wells on production; (xxiii) preliminary and estimated DCET costs and completion costs; (xxiv) targeted plateau production at

Kaybob Smoky Duvernay and Kaybob North Duvernay and the timing thereof; (xxv) the expected realization of capital cost efficiencies at Kaybob Smoky Duvernay and Kaybob North Duvernay and the potential impact on per well DCET costs; (xxvi) the expectation that capital efficiencies will

improve over time at the Willesden Green property as the play develops; (xxvii) expected GHG reductions associated with controller upgrades and waste water infrastructure; (xviii) general business strategies and objectives and (xxix) the expectation that all holders will exercise their right to

convert their debentures into Common Shares prior to the redemption date.

Such forward-looking information is based on a number of assumptions which may prove to be incorrect. Assumptions have been made with respect to the following matters, in addition to any other assumptions identified in this presentation or Paramount’s continuous disclosure documents:

(i) future commodity prices and the potential impact of the COVID-19 pandemic thereon; (ii) the likely impact of the COVID-19 pandemic on operations; (iii) the ability to realize expected cost savings; (iv) royalty rates, taxes and capital, operating, processing, transportation, general &

administrative and other costs; (v) foreign currency exchange rates and interest rates; (vi) general business, economic and market conditions; (vii) the performance of wells and facilities; (viii) the ability of Paramount to obtain the required capital to finance its exploration, development and

other operations and meet its commitments and financial obligations; (ix) the ability of Paramount to obtain equipment, services, supplies and personnel in a timely manner and at an acceptable cost to carry out its activities; (x) the ability of Paramount to secure adequate product processing,

transportation, fractionation and storage capacity on acceptable terms and the capacity and reliability of facilities; (xi) the ability of Paramount to market its production successfully to current and new customers; (xii) the ability of Paramount and its industry partners to obtain drilling success

(including in respect of anticipated production volumes, reserves additions, product yields and resource recoveries) and operational improvements, efficiencies and results consistent with expectations; (xiii) the timely receipt of required governmental and regulatory approvals; (xiv) the receipt

of benefits under government programs; (xv) the application of regulatory requirements respecting abandonment and reclamation; (xvi) anticipated timelines and budgets being met in respect of drilling programs and other operations (including well completions and tie-ins, the construction,

commissioning and start-up of new and expanded facilities, including third-party facilities, and facility turnarounds and maintenance); and (xvii) in the case of the expectation that all holders will exercise their right to convert their debentures into Common Shares prior to the redemption date,

the assumption that the trading price of the Common Shares will continue to remain substantially above the conversion price of the debentures.

In addition to the above: (a) forecast 2021 free cash flow is based on the following assumptions for 2021: (i) the midpoint of forecast capital spending and production, (ii) $25 million in net abandonment and reclamation costs, (iii) realized pricing of $47.55/Boe (US$67.63/Bbl WTI,

US$3.94/MMBtu NYMEX, $3.59/GJ AECO), (iv) royalties of $4.60/Boe, (v) operating costs of $11.15/Boe and (vi) transportation and processing costs of $4.00/Boe; (b) the forecast of 2021 year end net debt to adjusted funds flow assumes the payment of a regular monthly dividend of $0.06

per Common Share commencing in November 2021 and the conversion of the Company’s $35 million of convertible debentures into Common Shares in the fourth quarter of 2021; (c) forecast 2022 free cash flow is based on the following assumptions for 2022: (i) the midpoint of forecast

capital spending and production, (ii) $33 million in net abandonment and reclamation costs, (iii) realized pricing of $53.70/Boe (US$74.44/Bbl WTI, US$4.35/MMBtu NYMEX, $3.95/GJ AECO), (iv) royalties of $6.65/Boe, (v) operating costs of $11.00/Boe and (vi) transportation and processing

costs of $3.85/Boe; (d) the forecasted timing of achieving the targeted net debt level and net debt to adjusted funds flow in the third quarter of 2022 assumes the payment of a regular monthly dividend of $0.06 per Common Share commencing in November 2021 and the conversion of the

Company’s $35 million of convertible debentures into Common Shares in the fourth quarter of 2021; (e) estimated 2023 free cash flow is based on the following assumptions for 2023: (i) the midpoint of expected capital spending and production, (ii) $40 million in abandonment and reclamation

costs, (iii) realized pricing of $48.55/Boe (US$67.39/Bbl WTI, US$3.56/MMBtu NYMEX, 3.28/GJ AECO), (iv) royalties of $5.95/Boe, (v) operating costs of $10.50/Boe and (vi) transportation and processing costs of $3.70/Boe; and (f) the Company’s expectation to not pay Canadian income

taxes within the next five years is based on the current tax regime, the Company's tax pools and the assumptions with respect to production, expenditures, commodity prices, royalties and costs in the five years ended 2026 set forth herein. Taxable income varies depending on total income

and expenses and Paramount’s estimate is sensitive to assumptions regarding commodity prices, production, cash from operating activities, capital spending levels and acquisition and disposition transactions. Changes in these factors could result in the Company paying income taxes earlier

than expected.

Although Paramount believes that the expectations reflected in such forward-looking information are reasonable based on the information available at the time of the preparation of this presentation, undue reliance should not be placed on the forward-looking information as Paramount can

give no assurance that such expectations will prove to be correct. Forward-looking information is based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Paramount

and described in the forward-looking information. These risks and uncertainties include and/or relate (but are not limited) to: (i) fluctuations in commodity prices, including in relation to the impact of the COVID-19 pandemic; (ii) changes in capital spending plans and planned exploration and

development activities; (iii) the potential for changes to preliminary anticipated 2023 capital expenditures prior to finalization and changes to the resulting expected or illustrative 2023 average sales volumes, free cash flow, adjusted funds flow, net debt, net debt to adjusted funds flow,

production per share and debt adjusted share growth and free cash flow growth, (iv) changes in foreign currency exchange rates and interest rates, (v) the uncertainty of estimates and projections relating to future revenue, free cash flow, future production, reserves additions, liquids yields

(including condensate to natural gas ratios), resources recoveries, well performance, royalty rates, taxes and costs and expenses; (vi) the ability to secure adequate product processing, transportation, fractionation and storage capacity on acceptable terms; (vii) operational risks in exploring

for, developing and producing natural gas and liquids, including the risks of spills, leaks or blowouts; (viii) the ability to obtain equipment, services, supplies and personnel in a timely manner and at an acceptable cost; (ix) potential disruptions or unexpected technical or other difficulties in

designing, developing, expanding or operating new, expanded or existing facilities (including third-party facilities); (x) processing, pipeline and fractionation infrastructure outages, disruptions and constraints; (xi) risks and uncertainties involving the geology of oil and gas deposits; (xii) the

uncertainty of reserves estimates; (xiii) general business, economic and market conditions; (xiv) the ability to generate sufficient cash flow from operating activities and obtain financing to fund planned exploration, development and operational activities and meet current and future

commitments and obligations (including product processing, transportation, fractionation and similar commitments and obligations); (xv) changes in, or in the interpretation of, laws, regulations or policies (including environmental laws); (xvi) the ability to obtain required governmental or

regulatory approvals in a timely manner and to enter into and maintain leases and licenses; (xvii) the effects of weather and other factors, including wildlife and environmental restrictions which affect field operations and access; (xviii) uncertainties regarding the timing and costs of future

abandonment and reclamation obligations and potential liabilities for environmental damage and contamination; (xix) uncertainties regarding aboriginal claims and in maintaining relationships with local populations and other stakeholders; (xx) the outcome of existing and potential lawsuits,

regulatory actions, audits and assessments; (xxi) uncertainties with respect to the impact of the COVID-19 pandemic; and (xxii) other risks and uncertainties described elsewhere in this presentation and in Paramount’s filings with Canadian securities authorities, including its Annual Information

Form for the year ended December 31, 2020 and its Management & Discussion and Analysis for the year ended December 31, 2020, which are available under the Company’s profile on SEDAR at www.sedar.com.

http://www.sedar.com/

Advisories

29

This document contains disclosures expressed as "Boe", "$/Boe", "MBoe", "MMBoe" and "Boe/d". Natural gas equivalency volumes have been derived using the ratio of six thousand cubic feet of natural gas to one barrel of oil when converting natural gas to Boe. Equivalency measures may

be misleading, particularly if used in isolation. A conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head. For the nine

months ended September 30, 2021, the value ratio between crude oil and natural gas was approximately 26:1. This value ratio is significantly different from the energy equivalency ratio of 6:1. Using a 6:1 ratio would be misleading as an indication of value.

This document contains references to “CGR”, “finding and development costs” and “recycle ratio”, metrics commonly used in the oil and natural gas industry. “Finding and development costs” are calculated by dividing: (i) total capital expenditures for the period (excluding corporate

expenditures and land and property acquisitions) by (ii) the net changes in reserves from the prior year from extensions/improved recovery, technical revisions and economic factors. Finding and development costs are a measure commonly used by management and investors to assess the

relationship between capital invested in oil and gas exploration and development projects and reserve additions associated with such projects. “Recycle ratio” is calculated by dividing netback per Boe by applicable finding and development costs. This metric is utilized by management and

investors to monitor reserve addition efficiencies relative to the netbacks achieved from such reserve additions. “CGR”, “finding and development costs” and “recycle ratio” do not have standardized meanings and may not be comparable to similar measures presented by other companies.

As such, they should not be used to make comparisons. Management uses these metrics for its own performance measurements and to provide shareholders with measures to compare the Company's performance over time; however, such measures are not a reliable indicator of the

Company's future performance and future performance may not compare to the performance in previous periods and therefore should not be unduly relied upon.

All information in this presentation respecting acres of land held is effective as of December 31, 2020.

Additional information respecting the Company’s oil and gas properties and operations is provided in the Company’s annual information form for the year ended December 31, 2020 which is available on SEDAR at www.sedar.com.

Non-GAAP Financial Measures

In this presentation, “adjusted funds flow”, “asset level free cash flow”, “free cash flow”, “net debt“, “net debt to adjusted funds flow” and “netback“ (collectively the "Non-GAAP Financial Measures") are used and do not have any standardized meanings as prescribed by International Financial

Reporting Standards (“IFRS”).

"Adjusted funds flow" refers to cash from (used in) operating activities before net changes in non-cash working capital, geological and geophysical expenses, asset retirement obligation settlements, closure costs, provisions and other, dispute settlements and transaction and reorganization

costs. Adjusted funds flow is used to assist management and investors in measuring the Company’s ability to fund capital programs and meet financial obligations, including the settlement of asset retirement obligations. Asset retirement obligation settlements are excluded from the

calculation of adjusted funds flow because such expenditures are not directly linked to the revenue generating activities of the Company. Paramount manages the timing of expenditures related to asset retirement obligation settlements in accordance with regulatory requirements and its

overall approach to managing its asset retirement obligations and, as a result, amounts incurred may vary significantly from period to period. Adjusted funds flow is not intended to represent cash from operating activities, net loss or any other GAAP measure and should not be construed as

being an alternative to, or more meaningful than, cash from operating activities as determined in accordance with IFRS.

“Asset level free cash flow” refers to aggregate netback from an asset during the period less capital expenditures with respect to such asset for the period. Asset level free cash flow is used by management and investors to assess the cash generating capacity of an asset.

Liquids

Bbl Barrels

Bbl/d Barrels per day

MBbl Thousands of barrels

NGLs Natural Gas Liquids

Condensate Pentane and heavier hydrocarbons

WTI West Texas Intermediate

Oil Equivalent

Boe Barrels of oil equivalent

MBoe Thousands of barrels of oil equivalent

MMBoe Millions of barrels of oil equivalent

Boe/d Barrels of oil equivalent per day

Natural Gas

GJ Gigajoules

GJ/d Gigajoules per day

Mcf Thousands of cubic feet

MMcf Millions of cubic feet

MMcf/d Millions of cubic feet per day

AECO AECO-C reference price

Oil and Gas Measures and Definitions

In addition, there are risks that may result in the Company changing, suspending or discontinuing its monthly dividend program, including changes to free cash flow, operating results, capital requirements, financial position, market conditions or corporate strategy and the need to comply with

requirements under debt agreements and applicable laws respecting the declaration and payment of dividends.

Certain forward-looking information in this presentation, including forecast free cash flow in 2021, 2022 and future periods and forecast 2021 year-end net debt to annual adjusted funds flow, may also constitute a “financial outlook” within the meaning of applicable securities laws. A financial

outlook involves statements about Paramount’s prospective financial performance or position and is based on and subject to the assumptions and risk factors described above in respect of forward-looking information generally as well as any other specific assumptions and risk factors in

relation to such financial outlook noted in this presentation. Such assumptions are based on management's assessment of the relevant information currently available and any financial outlook included in this presentation is provided for the purpose of helping readers understand

Paramount’s current expectations and plans for the future. Readers are cautioned that reliance on any financial outlook may not be appropriate for other purposes or in other circumstances and that the risk factors described above or other factors may cause actual results to differ materially

from any financial outlook.

The forward-looking information and statements contained in this presentation are made effective as of November 3, 2021. The internally estimated play data information for Karr, Wapiti, Kaybob Smoky Duvernay, Kaybob North Duvernay and Willesden Green contained at pages 8, 11, 15,

16 and 18 in this presentation has been prepared effective October 1, 2021. In each case, events or information subsequent to the applicable effective dates have not been incorporated.

Total Grande Prairie Region Kaybob Region Central Alberta and Other Region

Q3 2021 Q2 2021 Q1 2021 FY 2020 Q3 2021 Q2 2021 Q1 2021 FY 2020 Q3 2021 Q2 2021 Q1 2021 FY 2020 Q3 2021 Q2 2021 Q1 2021 FY 2020

Shale gas (MMcf/d) 207.1 205.8 197.8 156.7 145.8 132.2 120.6 77.2 36.9 39.3 42.1 43.8 24.4 34.3 35.1 35.7

Conventional natural gas (MMcf/d) 62.6 67.3 75.3 92 2.2 2.1 2 1.4 54.4 58 65.8 82.1 6 7.2 7.5 8.5

Natural gas (MMcf/d) 269.7 273.1 273.1 248.7 148 134.3 122.6 78.6 91.3 97.3 107.9 125.9 30.4 41.5 42.6 44.2

Condensate (Bbl/d) 29,670 26,784 27,017 19,334 26,639 24,086 23,974 15,991 2,072 2,319 2,611 2,885 959 379 433 458

Other NGLs (Bbl/d) 5,017 4,938 5,170 4,325 3,274 2,874 2,984 1,964 1,415 1,569 1,677 1,812 328 495 509 549

NGLs (Bbl/d) 34,687 31,722 32,187 23,659 29,913 26,960 26,958 17,955 3,487 3,888 4,288 4,697 1,287 874 942 1,007

Tight oil (Bbl/d) 475 494 479 462 - - – – 368 354 342 301 107 140 136 161

Light and Medium crude oil (Bbl/d) 2,032 2,265 2,358 2,768 9 4 – 14 1,979 2,224 2,321 2,709 44 37 37 46

Crude oil (Bbl/d) 2,507 2,759 2,837 3,230 9 4 – 14 2,347 2,578 2,663 3,010 151 177 173 207

Total (Boe/d) 82,150 79,995 80,540 68,340 54,586 49,345 47,385 31,076 21,054 22,688 24,938 28,685 6,510 7,962 8,217 8,579

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30

Product Type Information

Below is a complete breakdown of sales volumes for applicable periods by specific product type of shale gas, conventional natural gas, NGLs, tight oil and light and medium crude oil. Numbers may not add due to rounding.

“Free cash flow” refers to adjusted funds flow less total capital expenditures and asset retirement obligation settlements. Free cash flow is used by management and investors to assess the amount of internally generated cash available to repay debt, reinvest in the business or return to

shareholders.

"Net debt" is a measure of the Company’s overall debt position after adjusting for certain working capital amounts and is used by management to assess the Company’s overall leverage position. Refer to the Liquidity and Capital Resources section of the Company’s Management’s

Discussion and Analysis for the three and nine months ended September 30, 2021 for the calculation of Paramount’s net debt as of September 30, 2021.

“Net debt to adjusted funds flow” is a ratio calculated as the period end net debt divided by adjusted funds flow for the trailing four quarters. The ratio of net debt to adjusted funds flow is commonly used by management and investors to assess the Company’s overall debt position.

"Netback" equals petroleum and natural gas sales less royalties, operating expense and transportation and NGLs processing costs. Netback is commonly used by management and investors to compare the results of the Company’s oil and gas operations between periods.

Non-GAAP Financial Measures should not be considered in isolation or construed as alternatives to their most directly comparable measure calculated in accordance with GAAP, or other measures of financial performance calculated in accordance with GAAP. The Non-GAAP Financial

Measures are unlikely to be comparable to similar measures presented by other issuers.

Karr Wapiti

Q3 2021 Q2 2021 Q1 2021 FY 2020 Q3 2021 Q2 2021 Q1 2021 FY 2020

Shale gas (MMcf/d) 113 106.3 89.1 55.6 32.7 25.9 31.5 21.5

Conventional natural gas (MMcf/d) 1.4 1.3 1.1 0.7 0.6 0.5 0.6 0.4

Natural gas (MMcf/d) 114.4 107.6 90.2 56.3 33.3 26.4 32.1 21.9

NGLs (Bbl/d) 20,805 20,739 18,203 11,389 9,100 6,211 8,751 6,550

Total (Boe/d) 39,878 38,679 33,230 20,777 14,651 10,604 14,107 10,207

Play Data

The internally estimated play data information for Karr, Wapiti, Kaybob Smoky Duvernay, Kaybob North Duvernay and Willesden Green contained at pages 8, 11, 15, 16 and 18 in this presentation has been prepared effective October 1, 2021 by internal qualified reserves evaluators

from Paramount in accordance with COGEH and using strip commodity prices and foreign exchange rates as at October 22, 2021 ranging from US$57.81 to US$81.95/Bbl WTI, $2.77 to $5.11/GJ AECO and an exchange rate of US$0.80 to US$0.81 for one Canadian dollar. The play

data has been prepared excluding certain wells with significant deviation in completion, lateral length, depletion or infrastructure constraints and has been adjusted for non-producing days. The play data contains no adjustments or assumptions respecting unscheduled potential future

facility and transportation constraints or outages. Underlying forecast economics are half-cycle economics and include only the cost to drill, complete, tie-in and equip wells. The forecasts do not take into account certain other costs, including those required to construct central

processing facilities, regional gathering facilities, condensate stabilization facilities and other infrastructure and costs related to water disposal and wellbore optimization. Sales and production volumes presented in the play data have been estimated on the basis of an equal likelihood

that actual volumes recovered will be greater or less than those estimated.

The metrics and terms “CGR”, “IP 365“, “IP 365 CGR”, “Sales Volumes”, “Average CGR”, “Sales Gas Volume”, “Sales Condensate”, “Implied Capital efficiency” and “DCET” are used in presenting play data. “CGR” means condensate to gas ratio and, except otherwise noted, is

calculated by dividing sales condensate volumes by sales natural gas volumes. “IP 365” means the estimated average daily sales volumes of production over the initial 365 calendar days of production. “IP 365 CGR” means the estimated average CGR over the initial 365 calendar days

of production. “Sales Volume” means the estimated aggregate potential sales volumes of production. “Average CGR” means the estimated average CGR over the life of the well. “Sales Gas Volume” means the estimated aggregate potential sales volumes of natural gas. “Sales

Condensate” means the estimated aggregate potential sales volumes of condensate. “Implied Capital Efficiency” is calculated by dividing IP365 by DCET. “DCET” means estimated drilling, completion, equip and tie-in costs.

The play data contained in this presentation has been included for the purposes of informing readers as to certain assumptions and estimates relied on by management of Paramount as of the date of preparation for capital budgeting and forecasting purposes. The play data represents

an estimate only respecting undeveloped locations subject to near-term development, is subject to revision and may not be applicable to all undeveloped locations. Play data should not be relied on as an estimate or evaluation of reserves or resources associated with the Company’s

properties and readers are referred to the McDaniel Report and to the Company's annual information form for the year ended December 31, 2020, which is available on SEDAR at www.sedar.com, for reserves information respecting the Company.

Undeveloped Locations

This presentation contains information respecting Paramount’s internal estimate of future potential undeveloped locations at various properties. The future potential undeveloped location information contained in this presentation represents gross locations and was prepared effective

October 1, 2021 by internal qualified reserves evaluators from Paramount. The undeveloped locations referred to in this presentation were determined by Paramount’s internal evaluators based on, among other matters, their assessment of available reservoir, geological and technical

information, the economic thresholds necessary for development and potential future development plans. There is no certainty that the Company will drill any of the identified future potential undeveloped locations and there is no certainty that such locations will result in additional

reserves or production. The locations on which the Company will actually drill wells, including the number and timing thereof will be dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional

reservoir, geological and technical information that is obtained and other factors. While certain of the estimated undeveloped locations have been de-risked by drilling existing wells in relative close proximity to such locations, many of the locations are further away from existing wells

where management has less information about the characteristics of the reservoir and therefore there is more uncertainty as to whether wells will be drilled in such locations, and if wells are drilled in such locations there is more uncertainty that such wells will result in additional oil and

natural gas reserves or production. This presentation references the percentage of future potential undeveloped locations assigned reserves in the McDaniel Report solely to provide the reader with additional information concerning the proportion of internally estimated future potential

undeveloped locations as compared to locations assigned reserves in the McDaniel Report. The comparability of internally estimated future potential undeveloped locations to locations assigned in the McDaniel Report is limited due to differing effective dates and assumptions. There is

no guarantee that any internally estimated future potential development location will be included and assigned reserves in any future reserves report prepared for the Company.

Advisories

31

The Company forecasts that:

• Fourth quarter 2021 sales volumes will average between 85,000 Boe/d and 86,500 Boe/d (55 percent shale gas and conventional natural gas combined, 39 percent light and medium crude oil, tight oil and condensate combined and 6 percent other NGLs)

• 2021 annual sales volumes will average approximately 82,000 Boe/d (56 percent shale gas and conventional natural gas combined, 38 percent light and medium crude oil, tight oil and condensate combined and 6 percent other NGLs)

• 2022 sales volumes will average between 90,000 Boe/d and 94,000 Boe/d (54 percent shale gas and conventional natural gas combined, 40 percent light and medium crude oil, tight oil and condensate combined and 6 percent other NGLs)

• First half 2022 sales volumes are expected to average between 81,000 Boe/d and 85,000 Boe/d (56 percent shale gas and conventional natural gas combined, 38 percent light and medium crude oil, tight oil and condensate combined and 6 percent other NGLs)

• Second half 2022 sales volumes are expected to average between 99,000 Boe/d and 103,000 Boe/d (53 percent shale gas and conventional natural gas combined, 41 percent light and medium crude oil, tight oil and condensate combined and 6 percent other NGLs)

Reserves Data

Reserves data set forth in this presentation is based upon an evaluation of the Company’s reserves prepared by McDaniel & Associates Consultants Ltd. (“McDaniel”) dated March 2, 2021 and effective December 31, 2020 (the “McDaniel Report”). The price forecast used in the

McDaniel Report is an average of the January 1, 2021 price forecasts for McDaniel and GLJ Petroleum Consultants Ltd. and the December 31, 2020 price forecast of Sproule Associates Ltd. The estimates of reserves contained in the McDaniel Report and referenced in this document

are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates contained in the McDaniel Report and referenced in this document. There is no assurance that the forecast prices and costs

assumptions used in the McDaniel Report will be attained, and variances could be material. Estimated future net revenue does not represent fair market value. The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all

properties, due to the effects of aggregation. Readers should refer to the Company's annual information form for the year ended December 31, 2020, which is available on SEDAR at www.sedar.com, for a complete description of the McDaniel Report (including reserves by specific

product type of shale gas, conventional natural gas, NGLs, tight oil and light and medium crude oil) and the material assumptions, limitations and risk factors pertaining thereto.

Paramount Resources Ltd.

2800 – 421 7 Avenue S.W.

Calgary, Alberta Canada

T2P-4K9

Telephone: 403.290.3600

www.paramountres.com

paramount resources ltd. november 2021 corporate presentation

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