paramount resources ltd. august 2021 corporate presentation

August 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.

• 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 August 3, 2021. Certain internally estimated play data contained in this presentation was prepared effective September 1, 2020. In each case, events or information subsequent to the applicable effective dates have not been incorporated.

• This presentation refers to sales volumes of "liquids", "natural gas", "condensate and oil" and "other NGLs". “Liquids" means NGLs (including condensate) and oil combined, "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 and "other NGLs" refers to ethane, propane and butane combined. See the Product Type Information section of the 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

Grande Prairie (84%)

Kaybob (5%)Central (8%)

Growth (35%)

Growth (19%)Corporate (2%)

Discretionary Growth (16%)

-

$50

$100

$150

$200

$250

$300

$350

$400

Region Category Category

68,340

80,540 79,995 80,000

84,000 82,000

88,000

65,000

70,000

75,000

80,000

85,000

90,000

2020A 1Q21A 2Q21A 2021F 2022F

Shares Outstanding (MM) 134.9

Market Capitalization ($MM) (3) ~$2,180

Net Debt at June. 30, 2021 ($MM) (4) ~$725

Enterprise Value ($MM) ~$2,900

Monthly Dividend ($/share | Annualized Yield) (5) $0.02 | 1.5%

Production (MBoe/d | % Liquids) 80 – 82 | 44% 84 – 88 | 45%

Capital Expenditures ($MM) $265-$285 $325-$385

ARO ($MM) $25 $30

Midpoint Free Cash Flow ($MM) (4) ~$185 ~$320

Net Debt to Adjusted Funds Flow (4) ~1.0x <0.5x

-

10,000

20,000

30,000

40,000

50,000

60,000

2019A 2020A 2021F 2022F

Pro

du

ctio

n (B

oe/

d)

-

10,000

20,000

30,000

40,000

50,000

60,000

2019A 2020A 2021F 2022F

Pro

du

ctio

n (B

oe

/d)

43% Liquids

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)

• Q2 2021 Production: 79,995 Boe/d (43% liquids)

• Inaugural monthly dividend paid in July 2021

Focus Areas

Market Snapshot (TSX-POU) Guidance Summary 2021F 2022F (6)

Production Outlook Range (Boe/d)

(1) Consists of common shares held by directors, officers and other insiders. (2) See Advisories Appendix – Reserves Data. (3) 134.9MM shares at $16.15/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 $16.15. (6) 2022 amounts are current expectations based on preliminary planning and current market conditions and are subject to change.

44%

Liquids

39% Liquids

Natural Gas

Other NGLs

Condensate and Oil

Kaybob and Central

Grande Prairie

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

45%

Liquids

Wapiti/Karr Montney

Kaybob Montney/Duvernay

Willesden Green Duvernay

Capital Outlook ($MM)

Sustaining Capital and

Maintenance Activity(65%)

Sustaining Capital and

Maintenance Activity(65%)

(6)

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

43% Liquids

2021F Preliminary(Mid-point) 2022F (6)

-

$100

$200

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$400

$500

$600

$700

$800

$900

AFF CapEx ARO FCF AFF CapEx ARO FCF

2021F 2022F

$M

M

Free Cash Flow Generation and Debt Reduction

4

A significantly lower cost structure has helped to generate meaningful free cash flow and debt reduction

(1) The Company forecasts 2021 free cash flow of ~$185 million based on: (i) the midpoint of forecast capital spending and production, (ii) $25 million in abandonment and reclamation costs, (iii) realized pricing of $44.00/Boe (US$64.05/Bbl WTI, US$3.41/MMBtu NYMEX, $3.37/GJ AECO), (iv) royalties of $3.90/Boe, (v) operating costs of

$11.20/Boe, and (vi) transportation and processing costs of $4.00/Boe. 2022 amounts are current expectations based on preliminary planning and current market conditions and are subject to change. Such plans would be expected to result in 2022 free cash flow of ~$320 million based on: (i) the midpoint of expected capital spending and

production, (ii) $30 million in abandonment and reclamation costs, (iii) realized pricing of $43.20/Boe (US$62.18/Bbl WTI, US$3.30/MMBtu NYMEX, $3.10/GJ AECO), (iv) royalties of $4.15/Boe, (v) operating costs of $11.00/Boe and (vi) transportation and processing costs of $3.85/Boe (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) Debt adjusted share count calculated as share count plus (net debt divided by current share price).

• ~$168 million gross proceeds from dispositions in 2021:

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

• ~$88 million from sale of Birch asset in Q3

• $67 million cash settlement received from Strathcona in June 2021

2021F 2022F

Free Cash Flow Guidance ~$185 ~$320

Midpoint of CapEx Guidance ~$275 ~$355

ARO Guidance ~$25 ~$30

Illustrative Adjusted Funds Flow (“AFF”) ~$485 ~$705

Illustrative Net Debt ~$500 <$300

Illustrative Net Debt / Adjusted Funds Flow * ~1.0x <0.5x

YoY Production and FCF Growth

Production per Share Growth 19% 6%

Production per Debt Adjusted Share Growth (3) 34% 18%

Free Cash Flow Growth n/a 73%

• Paramount is prioritizing free cash flow as follows:

1) Debt reduction

2) Shareholder returns - Dividends and Share buybacks

3) Incremental growth - Organic development and Acquisitions

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

* If all forecast FCF was directed to debt reduction, 2022F year-end net debt / adjusted funds flow would be less than 0.5x

Illustrative AFF and FCF Estimates (1)(2)

@$40

~$110MM @US$40/Bbl WTI


$275MM

$25MM

Mid-point guidance~$185MM

WTI US$/Bbl:

@$50@$60@$70

@$40

WTI US$/Bbl:

@$50

@$60

@$70

$355MM

$30MM

Mid-point guidance~$320MM



• The Company has hedged ~53% of forecast midpoint H2 2021 production, which

provides free cash flow certainty

• Supports capital program of $265 - $285 million

• Protects positive free cash flow in 2021

2021F 2022F 2023F 2024F 2025F

GP

Ass

et L

evel

FC

F ($

MM

)

Grande Prairie Free Cash Flow Generation

5

Karr and Wapiti are expected to drive significant free cash flow in 2022 and beyond

(1) “Free cash flow” and “asset level free cash flow” are Non-GAAP Financial Measures. See Advisories Appendix - Non GAAP Financial Measures.

• Karr and Wapiti combined have the potential to generate significant asset level

free cash flow in 2022 and beyond

• The illustrative Grande Prairie asset level free cash flow to the right assumes

plateau production of 66,000 – 70,000 Boe/d is reached by 2023, per unit

operating netbacks consistent with those in H1 2021 and capital expenditures

ranging between $220 million and $290 million over the periods between 2021

and 2025

• Over the 5 year period, estimated cumulative asset level free cash flow is

approximately $2.1 billion at the midpoint of plateau production

Illustrative Cumulative 2021-2025F Grande Prairie

Asset Level Free Cash Flow Potential (1)

Karr

Wapiti

Montney Oil

Willesden Green

Smoky

Ante CreekKaybob North

Kaybob South

-

50%

100%

150%

200%

250%

- 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 later stages of

development available for reinvestment and debt

reduction

• 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 to be

considered 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 April 19, 2021 of rate of return vs. total value assuming full field development on a rela tive 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

Smoky

Kaybob North

Dashed circles represent updated IRR/total value

assuming DCET costs are scaled to those of Karr/Wapiti

Willesden Green

Kaybob South

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 $88MM

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 55 wells brought onstream to the end of 2020

• 2021 activities include 20 drills, 19 completions and 19 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 $290 million to $320 million (2)

• Management high-graded undeveloped location count of 235 wells (Middle Montney only)

• ~60% 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

• 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

10 wells at the 16-17

pad (only 7 to be drilled

in 2021)

• Commence completion

operations on 5 wells

on the 5-16 East pad in

late Q3

• Finish completions,

and tie-in and bring on

production 5 wells at

the 5-16 East pad

38,000

40,000 39,000

40,000 42,000 42,000

33,230

38,679

30000

35000

40000

45000

1Q21A 2Q21A 3Q21F 4Q21F 2022F

52% Liquids

51% Liquids 50% Liquids

(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 Karr per-unit netbacks of $28.23/Boe, consistent with the

first half of 2021, and 12 to 16 new wells per year at an average DCET cost of $7.5 million per well, excluding the cost of any potential incremental infrastructure requirements in the future. (3) See Advisories Appendix – Undeveloped Locations.

55% Liquids

54% Liquids

-

250

500

750

1,000

1,250

1,500

- 250 500 750 1,000 1,250 1,500 1,750

MB

oe

Producing Days

-

100

200

300

400

500

600

700

800

900

- 250 500 750 1,000 1,250 1,500 1,750

MB

bl

Producing Days

Cumulative Boe – Karr Wells

8

Karr Performance and Recent HighlightsParamount’s Montney wells at Karr continue to exhibit strong production

(1) Production measured at the wellhead. Natural gas sales volumes are lower by approximately 7 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) Production measured at the wellhead. Natural gas sales volumes are lower by

approximately 7 percent and liquids sales volumes are lower by approximately 6 percent due to shrinkage. (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 NGLs – Karr Wells • Highly productive liquids-rich wells drive industry-

leading half-cycle economics

• Implied capital efficiency of ~$6,700/Boe/d (3)

• PDP finding and development costs were

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

• Results in a recycle ratio of 1.2x when using

Karr’s 2020 operating netback of $10.83/Boe

and 3.2x when using Karr’s H1 2021

operating netback of $28.23/Boe

IP 365 (Boe/d) 1,126

IP 365 CGR (Bbl/MMcf) 233

Sales Volume (MBoe) 1,196

Average CGR (Bbl/MMcf) 150

Sales Gas Volume (Bcf) 4.0

Sales Condensate (MBbl) 549

DCET ($MM) $7.5

Play Data (3)

Type Curve (2)

Type Curve (2)

Recent Highlights

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

2021, two months ahead of schedule, continues to outperform

internal type well projections resulting in all wells paying out in just

four months

• DCET costs averaged $6.6MM/well on this pad

• Brought onstream three wells on the 4-28 pad in late April

• DCET costs averaged $7.0MM/well on this pad

• Averaged 1,295 Boe/d (3.4 MMcf/d of shale gas and 728 Bbl/d

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

average CGR of 214 Bbl/MMcf (1)

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

preliminary DCET costs averaged an estimated $6.0MM/well

• Achieved operating costs of $9.40/Boe in the second quarter of

2021, lower than targeted operating costs at Karr of $10.00/Boe

at plateau production of approximately 40,000 Boe/d

• Over-pressured window of Karr Montney has been expanded to

include northeast portion of Karr lands resulting in increased

potential well inventory

$6.9 MM/well

$4.1 MM/well

$3.7 MM/well

$3.6 MM/well

$3.4 MM/well

$3.8 MM/well

$2.9 MM/well

$200

$400

$600

$800

$1,000

-

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$7.0

$8.0

1-19 Pad

(H2 2019)

12-18 Pad

(Q1 2020)

2-1 Pad

(Q2 2020)

5-16W Pad

(Q3 2020)

3-10 Pad

(Q1 2021)

4-28 Pad

(Q2 2021)

7-18 Pad

(Q3 2021)

$/to

nn

e$M

M

Total Completion Cost (Left Axis)

Completion Cost / Tonne of Proppant (Right Axis)

0

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3,000

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6,000

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pth

(M

ete

rs)

Days from Spud

Pacesetter (2021)

2021 - Average

2020 - Average

2019 - Average

2018 - Average

9

Karr Capital EfficienciesParamount’s focus on continuous improvement is resulting in consistently lower well costs

Drilling Days Completion Costs

• DCET costs on the 7-18 pad averaged ~$6.0 million per well, representing an ~11% reduction relative to average DCET costs of the last two pads at Karr

• The average spud to rig release time on the recently drilled 5-16 East pad was just under 24 days, 12% faster than on the 5-16 West pad drilled last year from the same surface location

• Continued focus on innovation, technological advancement and efficient execution has resulted in further cost reductions without compromising well deliverability

Pacesetter (2021)

7-18 pad

- 313 m/day

- 6,341 mMD

- 20.2 days

(1)

(1) 7-18 Pad costs are estimated final field costs and are subject to change.

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$MM

0.0x

1.0x

2.0x

3.0x

4.0x

5.0x

6.0x

10

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 Jul 1, 2021 Price Deck) divided by DCET by Well (Right Axis)

Actual Netback to May 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 July 1, 2021 price forecasts for McDaniel and GLJ Petroleum Consultants Ltd. and the June 30, 2021 price forecast of Sproule Associates Ltd.

2016/17 Program2.2x Avg/Well

2019 Program2.5x Avg/Well



$13.3 MM$11.9 MM

$12.3 MM

$7.8 MM

Wells exhibit strong returns and quick payouts

$6.7 MM


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

11

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

• Development commenced in 2018 with 29 wells brought onstream to the end of 2020

• 2021 activity includes the drilling of 12 wells, the completion of 14 wells and the tie-in of 15 wells

• Takeaway capacity in place to support Montney production growth

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

• Management full field development location count of 204 wells

• ~72% assigned reserves as at December 31, 2020 (1)

• Supports 20+ years of production at plateau

Quarterly Production (Boe/d) and Activity Outlook

• 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

• Brought on production

7 wells on the 6-4 pad

• 10 day scheduled

facility outage

• Drill one tenure well

• Complete and bring

onstream 7 wells on

the 9-22 pad by year-

end

• Tie-in and bring

onstream the

previously D&C 10-22

pad well

12,500 14,000

18,000 15,500 17,000

21,000

14,107

10,604

5000

10000

15000

20000

25000

1Q21A 2Q21A 3Q21F 4Q21F 2022F

59% Liquids

61% Liquids60% Liquids

58% Liquids

(1) See Advisories Appendix – Undeveloped Locations.

62% Liquids

-

50

100

150

200

250

300

350

400

450

500

- 200 400 600 800

MB

oe

Producing Days

-

50

100

150

200

250

300

- 200 400 600 800

MB

bl

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

Plans include:

• Drill, complete, tie-in and bring on production seven new

Montney wells at the 9-22 pad and tie-in and bring on

production one well previously drilled and completed at the

adjacent 10-22 pad

• Install associated infrastructure

Benefits:

• Higher 2021 production exit rate

• Improved 2022+ asset level free cash flow profile

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

encouraging initial results

• DCET costs averaged $6.9 million per well

12

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

• Implied capital efficiency of ~$9,200/Boe/d using

the Company’s assumptions (2)

• PDP finding and development costs were

$8.96/Boe in the Grande Prairie Region in 2020 (3)

• Results in a recycle ratio of 1.4x when using

Wapiti’s 2020 operating netback of $12.10/Boe

and 3.1x when using Wapiti’s H1 2021

operating netback of $27.86/Boe

IP 365 (Boe/d) 856

IP 365 CGR (Bbl/MMcf) 324

Sales Volume (MBoe) 880

Average CGR (Bbl/MMcf) 217

Sales Gas Volume (Bcf) 2.2

Sales Condensate (MBbl) 461

DCET ($MM) $7.9

Play Data (2)

(1) Production measured at the wellhead. Natural gas sales volumes are lower by approximately 14 percent and wellhead liquids sales volumes are lower by approximately 2 percent due to shrinkage, under normalized operations. (2) Per well data based on management estimates and price deck. See Advisories Appendix – Play Data.

(3) See Advisories Appendix – Oil and Gas Measures and Definitions.

Cumulative Boe – Wapiti Wells

Cumulative NGLs – Wapiti Wells

Type Curve (1)

Type Curve (1)

The Wapiti Type Curve has been updated to

reflect an optimized well completion, in line with

Paramount’s go forward plan. This results in an

uplift to the curve relative to historic results

$6.6 MM/well

$6.1 MM/well

$4.0 MM/well

$3.3 MM/well

-

$200

$400

$600

$800

-

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$7.0

$8.0

9-3 Pad

(2018)

5-3 Pad

(2019)

5-3 West Pad

(2020)

6-4 West Pad

(2021)

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Completion Cost (Left Axis)

Completion Cost / Tonne of Proppant (Right Axis)

0

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3,000

4,000

5,000

6,000

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pth

(M

ete

rs)

Days from Spud

Pacesetter (2020)

2021 - Average

2020 - Average

2019 - Average

2018 - Average

13

Wapiti Capital EfficienciesParamount continues to focus on optimizing well design at Wapiti and recently successfully tested three monobore wells

Drilling Days Completion Costs

• Monobore wells benefit from lower drilling and completion costs and higher frac fluid pumping rates relative to conventional multi casing wellbores

• DCET costs averaged a pacesetting $6.9 million per well on the 6-4 pad, representing a nine percent reduction compared to average Wapiti DCET costs in 2020

Pacesetter (2020)

5-3 East pad

- 372 m/day

- 5,713 mMD

- 15.4 days

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$MM

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14

Wapiti Performance

Wapiti Well Performance by Program


$11.3 MM


$9.6 MM


$7.6 MM

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

Actual Netback to May 31, 2021 (1) (Left Axis)

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

Average DCET by Program (Left Axis)

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

Lifetime Netback (Actual + Forecast Using Jul 1, 2021 Price Deck) divided by DCET by Well (Right 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 July 1, 2021 price forecasts for McDaniel and GLJ Petroleum Consultants Ltd. and the June 30, 2021 price forecast of Sproule Associates Ltd.

15

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

• 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

• Continued focus on operational excellence and improving the cost structure

have been especially impactful in the Kaybob Region, resulting in significant

cost savings compared with previous years

16

Kaybob and Central OverviewAssets have significant upside with a great deal of running room. Limited capital is currently being deployed

Kaybob Smoky Duvernay Kaybob North Duvernay

• Competitor activity continues to de-risk Paramount land• Preliminary plans to DCET a three well pad in 2022 (on an

existing pad where one of the wells was drilled in 2019)• ~172 full field development locations (~40% assigned

reserves as at December 31, 2020) (1)

• The Kaybob Smoky Duvernay asset has been de-risked with competitor wells surrounding Paramount’s lands

• Preliminary plans to DCET a four well pad in 2022• ~59 full field development locations (~44% assigned

reserves as at December 31, 2020) (1)

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

• ~85 (gross) full field development locations (~35% assigned reserves as at December 31, 2020) (1)

Kaybob South Duvernay


17

Kaybob and Central Overview (Cont’d)Assets have significant upside with a great deal of running room. Limited capital is currently being deployed

Kaybob North Montney Oil Ante Creek Montney Oil

• Recently completed, tied-in and brought on production one well that was drilled in 2020

• ~81 full field development locations (~1% assigned reserves as at December 31, 2020) (1)

• Enhanced oil recovery pilot project in 2021 will assess the viability of implementation across the entire field


• Drilled, completed and equipped two wells on the 4-7 pad that are expected to be brought on production in late August


Willesden Green Duvernay


The 5-29 well is one of the best

performing Duvernay oil wells in

Willesden Green to date

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

and a total MD of ~7,400m (longest

horizontal well drilled by the Company)

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”)

18

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

19

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

34%

19% 7%

12%

28%

Credit Facility and Risk Management

20

Paramount has an active market risk diversification and risk management strategy

The Company has undertaken an active hedging program to provide greater funds flow

certainty and further protect the capital program

• ~53% of forecast midpoint production is hedged over the second half of 2021

• 6,000 Bbl/d of oil and ~39,000 MMcf/d of natural gas hedged in Q1 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

2021F 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)

• Approximately $575 million drawn at June 30, 2021 (1)

• Completed a private placement of $35 million of senior unsecured convertible debentures in January 2021

(1) Drawings on facility presented net of $3.8 million in unamortized transaction costs.

Strategic and Long-Term Investments

21

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

Summary of Investments & Other Assets

Investments in Public Companies(1) ~$180 million

Investments in Private Companies(2) ~$45 million

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

Undeveloped Land Not quantified

Total ~$285 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

Other Long Term Resources

Liard Basin natural gas

Mackenzie Delta natural gas

Cavalier Energy thermal oil

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

• 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

(1) Market value of public companies as at June 30, 2021 (includes 39.8 million shares of NuVista Energy Ltd. @ $3.98/share). (2) Carrying value as at June 30, 2021. For further details refer to Paramount’s consolidated financial statements as at June 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.)

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

• Strong liquidity position with year-end 2021F net debt to adjusted funds flow of ~1.0x (1)

• Stakeholder-aligned management and board with significant insider ownership

• Incremental shareholder returns with the recent implementation of an inaugural monthly dividend

22

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)

4-28 Pad

00/08-27-066-04W6/0 1,482 882 3.6 245 114 69 272 252 100

00/09-27-066-04W6/0 1,019 524 3.0 176 88 49 237 206 103

02/16-32-066-04W6/2 1,384 777 3.6 213 119 66 316 208 104

Avg. per well $7.0 1,295 728 3.4 214 107 61 275 224 102

3-10 Pad

00/01-34-065-05W6/0 1,992 1,019 5.8 175 295 155 841 184 168

00/02-34-065-05W6/0 2,527 1,513 6.1 249 353 201 911 221 176

00/03-34-065-05W6/0 2,103 1,091 6.1 180 323 166 944 176 179

02/01-34-065-05W6/0 2,053 1,074 5.9 183 321 170 905 188 172

02/02-34-065-05W6/0 2,025 995 6.2 161 312 155 942 165 176

02/03-34-065-05W6/0 2,095 1,207 5.3 226 324 171 916 187 175

Avg. per well $6.6 2,133 1,150 5.9 195 321 170 910 186 174

5-16 West Pad

00/04-18-066-05W6/0 1,255 909 2.1 438 245 156 531 294 259

00/05-18-066-05W6/0 1,620 882 4.4 199 359 218 848 257 252

00/12-18-066-05W6/0 1,941 1,120 4.9 227 427 240 1,126 213 259

02/04-18-066-05W6/0 1,683 961 4.3 222 340 183 944 194 261

02/05-18-066-05W6/0 1,717 905 4.9 186 378 182 1,176 154 253

Avg. per well $7.5 1,643 955 4.1 232 350 196 925 212 257

2-1 Pad

03/14-12-066-05W6/0 1,386 453 5.6 81 419 147 1,632 90 338

04/16-12-066-05W6/0 1,406 536 5.2 103 390 149 1,447 103 336

05/15-12-066-05W6/0 1,465 588 5.3 112 419 167 1,513 110 337

05/16-12-066-05W6/0 1,505 680 4.9 138 417 185 1,392 133 338

06/15-12-066-05W6/0 1,340 556 4.7 118 389 147 1,454 101 336

Avg. per well $7.0 1,420 563 5.1 109 407 159 1,488 107 337

12-18 Pad

5 wells (Avg. per well) $8.8 1,561 1,193 2.2 539 248 175 436 403 357

2019 Wells

8 wells (Avg. per well) $12.3 1,825 1,262 3.4 373 510 315 1,173 268 637

2018 Wells

5 wells (Avg. per well) $11.9 1,760 1,051 4.3 247 695 364 1,986 183 837

2016/2017 Wells

27 wells (Avg. per well) $13.3 1,969 1,171 4.8 245 824 409 2,493 164 1,148

Peak 30-Day (1)

Cumulative (2)

Days on

Production

24

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 7 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 July 31, 2021. Natural gas sales volumes are approximately 7 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)

5-3 West Pad

00/07-16-068-06W6/0 1,124 798 2.0 407 195 134 369 363 226

00/10-28-067-06W6/0 1,274 814 2.8 295 196 114 492 231 217

02/07-16-068-06W6/0 1,195 838 2.1 391 177 122 326 376 199

02/10-28-067-06W6/0 1,248 790 2.7 288 165 96 416 231 187

03/09-28-067-06W6/0 1,105 733 2.2 329 205 123 493 250 237

Avg. per well $7.6 1,189 795 2.4 336 188 118 419 281 213

5-3 East Pad

03/11-27-067-06W6/0 2,013 1,241 4.6 268 363 192 1,028 186 539

04/06-15-068-06W6/0 1,567 1,053 3.1 341 295 177 706 251 501

02/09-28-067-06W6/0 1,694 1,055 3.8 275 274 155 711 218 415

02/11-27-067-06W6/0 1,931 1,209 4.3 279 361 205 936 219 523

00/12-27-067-06W6/0 1,315 868 2.7 323 263 146 706 206 459

02/12-27-067-06W6/0 1,843 1,191 3.9 304 336 177 956 185 463

00/09-28-067-06W6/0 1,526 1,012 3.1 328 291 163 768 213 432

03/06-15-068-06W6/0 1,312 918 2.4 389 291 183 651 281 468

00/05-15-068-06W6/0 1,287 895 2.3 381 234 154 480 321 450

02/05-15-068-06W6/0 1,484 997 2.9 342 290 180 664 270 449

00/08-16-068-06W6/0 1,339 878 2.8 318 291 185 633 293 449

02/08-16-068-06W6/0 1,743 1,214 3.2 382 243 168 454 369 358

Avg. per well $9.6 1,588 1,044 3.3 320 294 174 724 240 459

9-3 Pad

11 wells (Avg. per well) $11.1 1,051 722 2.0 366 346 209 823 253 686

Peak 30-Day (1)

Cumulative (2)

Days on

Production

25

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 14 percent lower and NGLs sales volumes are approximately 2 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 July 31, 2021. Natural gas sales volumes are approximately 14 percent lower and NGLs sales volumes are approximately 2 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

27

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 certain periods within 2021; (iii) planned capital expenditures in 2021 and the allocation

thereof; (iv) planned abandonment and reclamation activities and expenditures; (v) forecast or illustrative 2021 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; (vi) preliminary

anticipated capital expenditures in 2022 and the resulting expected or illustrative 2022 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; (vii) Paramount’s

priorities for the allocation of free cash flow; (viii) the potential for Karr and Wapiti to generate significant asset level free cash flow in 2022 and beyond and illustrative asset level free cash flow potential at Grande Prairie; (ix) the number of wells per year required to maintain plateau production

at Karr; (x) undeveloped locations for certain properties and the years of plateau production supported by undeveloped locations at Karr and Wapiti; (xi) the targeted date for achieving plateau production at Wapiti; (xii) play data, anticipated well performance and forecast netback; (xiii)

exploration, development and associated operational plans and strategies; (xiv) preliminary and estimated DCET costs and completion costs; (xv) expected GHG reductions associated with controller upgrades and waste water infrastructure; and (xvi) general business strategies and

objectives.

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) in the case of the payment of future dividends under the Company’s monthly dividend program, assumptions as to the Company’s future

free cash flow, operating results, capital requirements and financial position; (iv) the ability to realize expected cost savings; (v) royalty rates, taxes and capital, operating, processing, transportation, general & administrative and other costs; (vi) foreign currency exchange rates and interest

rates; (vii) general economic, market and business conditions; (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; (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 performance of wells and facilities; (xiv) the timely receipt of required governmental and regulatory approvals; (xv) the application of laws and regulations, including environmental laws; (xvi) the geological characteristics of the Company’s

properties; and (xvii) anticipated timelines and budgets being met in respect of drilling programs, facility construction, facility maintenance and outages and other operations.

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. There are no assurances as to the continuing declaration and payment of future dividends under the Company’s monthly dividend program or the amount or timing of any such dividends. 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 2022 capital expenditures

prior to finalization and changes to the resulting expected or illustrative 2022 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. 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 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, other than those pertaining to dividends, are made effective as of August 3, 2021. The internally estimated play data information for Karr and Wapiti contained at pages 8 and 12 in this presentation has been

prepared effective September 1, 2020. In each case, events or information subsequent to the applicable effective dates have not been incorporated.

Advisories

28

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 six

months ended June 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.

“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 six months ended June 30, 2021 for the calculation of Paramount’s net debt as of June 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 and to

measure the strength of the Company's balance sheet.

"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.

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

Total Grande Prairie Region Kaybob Region Central Alberta and Other Region

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

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

Conventional natural gas (MMcf/d) 67.3 75.3 92 2.1 2.0 1.4 58.0 65.8 82.1 7.2 7.5 8.5

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

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

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

NGLs (Bbl/d) 31,722 32,187 23,659 26,960 26,958 17,955 3,888 4,288 4,698 874 942 1,007

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

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

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

Total (Boe/d) 79,995 80,540 68,340 49,345 47,385 31,076 22,688 24,938 28,685 7,962 8,217 8,579

Karr Wapiti

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

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

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

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

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

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

Advisories

29

The Company forecasts that 2021 sales volumes will average between 80,000 Boe/d and 82,000 Boe/d (56% shale gas and conventional natural gas combined, 38% light and medium crude oil, tight oil and condensate combined and 6% other NGLs). Second half 2021 sales volumes

are expected to average between 80,000 Boe/d and 84,000 Boe/d (55% shale gas and conventional natural gas combined, 39% light and medium crude oil, tight oil and condensate combined and 6% 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.

Product Type Information

This document refers to sales volumes of "liquids", "natural gas", "condensate and oil" and "other NGLs". "Liquids" means NGLs (including condensate) and oil combined, "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 and "other NGLs" refers to ethane, propane and butane. 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.

Advisories

30

Property

Referenced Undeveloped

Locations

Locations Assigned

Reserves in the McDaniel

Report

Karr (Middle Montney) 235 141

Wapiti 204 146

Kaybob Smoky Duvernay 59 26

Kaybob North Duvernay 172 68

Kaybob South Duvernay ~85 30

Kaybob North Montney Oil ~28 22

Ante Creek Montney Oil ~81 1

Willesden Green Duvernay ~112 18

Play Data

The play data for Karr and Wapiti contained at pages 8 and 12 in this presentation has been prepared effective September 1, 2020 by internal qualified reserves evaluators from Paramount using strip pricing at the time of preparation ranging from US$41.67 to US$48.21/Bbl WTI, $2.05

to $3.16/GJ AECO and an exchange rate of US$0.76 for one Canadian dollar until 2024 and US$0.75 to one Canadian dollar thereafter. 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 where noted on pages 8, 24

and 25, 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 future potential undeveloped locations at various properties. The future potential undeveloped location information contained in this presentation represents gross locations and was prepared effective December 31, 2020 by internal

qualified reserves evaluators from Paramount. The table below sets out, for the referenced gross undeveloped locations of each applicable property, the number of locations that were assigned reserves in the McDaniel Report.

The undeveloped locations not assigned reserves in the McDaniel Report and 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.

Paramount Resources Ltd.

2800 – 421 7 Avenue S.W.

Calgary, Alberta Canada

T2P-4K9

Telephone: 403.290.3600

www.paramountres.com

paramount resources ltd. august 2021 corporate presentation

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