Corporate Presentation January 2020 Advisories In the interest of - - PowerPoint PPT Presentation

Corporate Presentation

January 2020

Advisories

2

• In the interest of providing information regarding Paramount Resources Ltd. ("Paramount", "PRL"
• r 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.

• Accordingly, recipients are cautioned that events or circumstances could cause actual results to

differ materially from those predicted.

• 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 and reserves data contained in this presentation.

• The forward-looking information and statements contained in this presentation are made effective

as of December 5, 2019. The type well information contained in this presentation has been prepared effective March 1, 2019, except where otherwise noted, and the drilling location information contained in this presentation was prepared effective January 1, 2019. In each case, events or information subsequent to the applicable effective dates have not been incorporated.

Early identification and low cost capture

• Large and diversified suite of horizons/zones to pursue, dependent on market conditions

Appraise and high-grade top tier economic returns

• Current Focus: liquids-rich Montney and Duvernay

Develop, Refine, Optimize

• Continuous improvement in all facets of technical understanding and execution

Harvest / Monetize

• Free cash flow positive full field development
• Well documented history of buying low and selling high

1) Net debt as of September 30, 2019 was ~$778 MM . Pro forma net debt includes proceeds from the November 2019 flow-through share issuance and the December 2019 sale of non-core assets in West Central

• Alberta. Refer to heading “Non-GAAP Measures” in the Advisories Appendix. 2) Represents position held by directors, officers and other insiders. 3) See the Advisories Appendix – Reserves Data.

Corporate Overview

3

Founded in 1976 (IPO’d in 1978), Paramount has a proven track record and strategy that generates above-average long term rates of return.

Quarterly Production Outlook Range (Boe/d)

Ticker Symbol - TSX POU Share Count 134.2 MM Market Cap @ $7.20/share ~$966 MM Net Debt - Sept 30/19 Pro Forma (1) ~$685 MM Enterprise Value ~$1.6 Bln Insider Ownership (2) ~ 47% 1P Reserves (3) 390.7 MMBoe 2P Reserves (3) 634.4 MMBoe

Paramount Market Snapshot

Montney and Duvernay Focus Areas

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Paramount is forecasting 2019F production of 81,000 to 85,000 Boe/d. The Montney and Duvernay account for ~45,000 Boe/d of this.

1) Excludes production from the Resthaven / Jayar asset that was sold in 2018. Stated acreage as at December 31, 2018.

(1)

(1)

Paramount Strategy

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Paramount has secured significant land positions in what is proving to be the most liquids-rich (and therefore economic) windows of the Montney and Duvernay.

• Large suite of high rate of return assets at various stages in the development lifecycle provides significant optionality

1) Based on Management’s estimates and price deck. See the Advisories Appendix – Type Well Information.

2019 Type Well Rate of Return (%) (1) Paramount Portfolio of Assets

2019 Budget and Production Guidance

2019F Capex Breakdown ($MM) (1)

6

2019F Budget and Production Guidance

• Capital budget down ~40% vs. 2018 program
• Prioritizing lower-risk and higher return, liquids-rich

Montney plays with the tie-in of 20 wells at Karr and Wapiti

• 5 well completions at Kaybob South Duvernay
• 3 well Montney Oil program
• Minor capex for emerging play land retention
• The $350 MM budget excludes the capital related to the

Karr 6-18 Facility expansion (“D2”)

• Paramount closed the sale of its Karr 6-18 facility

and related midstream assets for cash proceeds of ~$330 MM in August 2019

• Paramount was reimbursed at closing for the ~$75

MM already incurred to date to advance D2

• Sales volumes are expected to increase in the fourth

quarter of 2019 as Wapiti ramps up

Paramount has set a base 2019 capital budget of $350 MM to support annual production of 81,000 – 85,000 Boe/d; Q419 forecast to average 84,500 – 87,500 Boe/d.

(1)

1) Base 2019 capital budget, excluding land acquisitions and abandonment and reclamation.

2018 2019F Production (Boe/d) 85,941 81,000 - 85,000 Liquids (%) 37% 39% Capex ($MM) $569 $350 ARO ($MM) $29 $32

• A multi-stacked horizon, offering development potential over three

intervals

• Primary focus has been the Middle Montney with no reserves

bookings in other intervals

• Drilled and tested first Lower Montney

well in 2018 with results on par with the Middle Montney

• Two of the 2019 wells are targeting the

Lower Montney

• Will incorporate results to

determine inventory count

• Generated 2018 netback of ~$224 MM
• n capex of ~$169 MM (3)
• Type well drilling inventory can sustain greater than 40,000 Boe/d
• f production (post D2) for nearly two decades from the Middle

Montney alone

Karr Asset Overview

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Middle Montney Development Potential (2) Type Well (2)

1) See Advisories Appendix – Oil and Gas Measures and Definitions. CGRs stated are over a short period of time and are not necessarily indicative of long-term performance. Excludes days where wells did not produce. 2) Based on management estimates and price deck. See Advisories Appendix – Type Well Information. 3) See Advisories Appendix - Non-GAAP Measures.

Montney wells at Karr exhibit strong production rates and condensate yields with the recent 4-24 pad averaging gross peak 30-day production per well of 2,027 Boe/d (339 Bbl/MMcf). (1)

Karr Middle Montney Type Well Inventory (#) >250 Type Well Raw Gas Volume (Bcf) 4.0 Calculated Recovered Gas (Bcf) >1,000 Current Raw Gas Production Capacity (Mcf/d) 100,000 Implied Number of Years Production (Years) ~27 Raw Gas Production Capacity Post D2 (Mcf/d) 150,000 Implied Number of Years Production (Years) ~18 Return (%) 46% Payout (Months) 21 IP 365 (Boe/d) 961 Sales Vol. (MBoe) 1,481

• Avg. CGR (Bbl/MMcf)

173 DCET ($MM) $12.7

Gross Capacity

Current Post D2

Sour Raw Compression/Dehy

(MMcf/d)

100 80 Sour Raw Gas Processing

(MMcf/d)

• 70

Total Raw Gas Handling

(MMcf/d)

100 150 Raw Hydrocarbon Liquids Handling (Bbl/d) 15,000 30,000 Implied CGR @ Capacity

(Bbl/MMcf)

150 200 Raw Water Handling (Bbl/d) 15,000 28,000 Sales Gas Takeaway (MMcf/d) ~65 ~130

Karr Asset Overview (Cont’d)

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Processing and takeaway capacity is in place to support Montney growth at Karr.

Recent Developments

• The five Montney wells on the 4-24 pad were completed and brought on

production with an average peak 30-day rate per well of 2,027 Boe/d and a CGR of 339 Bbl/MMcf (1)

• Completion costs for these wells averaged $6.8 MM per well compared to

budgeted type-well completion costs of $7.7 MM

• Drilling was completed on three new wells on the 1-19 pad
• Wells are scheduled to be completed and brought onstream in the fourth

quarter

• Drilling was accelerated for ten Montney wells on two new 5-well pads
• riginally planned for 2020
• These wells will be brought onstream in 2020
• A new pacesetter drill cost was achieved on one of these wells of

approximately $2.9 MM compared to the budgeted type-well drilling cost

• f $4.0 MM per well
• Paramount is investing in additional water injection facilities in 2020 to add

incremental water disposal capacity

D2 Facility Expansion

• D2, which is scheduled to be completed in the second half of 2020, would add

70 MMcf/d of raw natural gas processing capacity and an additional 15,000 Bbl/d of raw liquids handling capacity

• As part of the sale agreement with CSV for the sale of the 6-18 Facility,

Paramount entered into a midstream services agreement that includes a fee for service arrangement, a reliability guarantee and a take-or-pay volume commitment that ends 20 years after the start-up of D2

• The commitment has been structured to minimize unutilized demand

charges as well as provide Paramount with flexibility to further develop its Karr resource play

1)See Advisories Appendix – Oil and Gas Measures and Definitions. CGRs stated are over a short period of time and are not necessarily indicative of long-term performance. Excludes days where wells did not produce.

CSV Karr 6-18 Facility Capacity

The Wapiti asset is a continuation of Karr and is characterized by multi-interval potential in the Montney. .

Wapiti Asset Overview

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Middle & Lower Montney Development Potential (1) Type Well (1)

• All eleven wells started-up on the Wapiti

9-3 pad had a cumulative average wellhead CGR of 336 Bbl/MMcf (2)

• CGR significantly exceeding type

curve

1) Based on management estimates and price deck. See Advisories Appendix – Type Well Information. 2) See Advisories Appendix – Oil and Gas Measures and Definitions. CGRs stated are over a short period

• f time and are not necessarily indicative of long-term performance. Excludes days where wells did not produce. 3) See Advisories Appendix - Non-GAAP Measures.

Return (%) 45% Payout (Months) 15 IP 365 (Boe/d) 1,395 Sales Vol. (MBoe) 1,594

• Avg. CGR (Bbl/MMcf)

80 DCET ($MM) $12.3 Wapiti Montney Type Well Inventory (#) >250 Type Well Raw Gas Volume (Bcf) 5.0 Calculated Recovered Gas (Bcf) >1,250 Wapiti Plant - Phase 1 Capacity (Mcf/d) 150,000 Implied Number of Years Production (Years) ~23

• All three intervals have been tested
• Wapiti is expected to generate free cash flow starting in 2020

upon completion of ramp up (3)

• Type well drilling inventory can sustain over 40,000 Boe/d of

production for over 20 years, based on Paramount’s high-graded inventory count in the Middle and Lower Montney

• Intention is to also develop the Upper Montney, which would

sustain that level of production for even longer

• Impacts from commissioning activity

are expected to diminish at the new Wapiti Plant as operations at the plant stabilize and throughput increases

Wapiti Asset Overview (Cont’d)

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Gas Processing and Takeaway (MMcf/d)

Initial flowback results at the new 5-3 pad have demonstrated higher initial production rates than the 9-3 pad, as a result of incorporating real-time learnings pad-over-pad.

Recent Developments

• Large scale development of Wapiti has commenced in earnest
• Sales volumes averaged 8,163 Boe/d in the third quarter, 74%

liquids

• Includes ~13 MMcf/d of natural gas and ~6,002 Bbl/d of liquids
• The 11 wells on the Wapiti 9-3 pad have been brought on

production

• The wells on the Wapiti 9-3 pad had a peak 30-day average

CGR of 378 Bbl/MMcf (1)

• Completion costs for the 9-3 pad averaged $5.5 MM per well

compared to a budgeted type-well completion cost of $7.8 MM

• CGR significantly exceeding type curve
• The 12 wells on the 5-3 pad have been drilled and completed
• Six of the 12 wells were temporarily brought on production

through inline test facilities in late-September and October with an average CGR of 337 Bbl/MMcf as at October 31, 2019 (1)

• Initial flowback results have demonstrated higher initial

production rates than the 9-3 pad, primarily due to flowing without tubular restrictions and a shorter cycle time between completion operations and initial flowback

• A new pacesetter drill cost was achieved on one of these wells
• f approximately $2.6 MM compared to the budgeted type-well

drilling cost of $3.5 MM per well

• The remaining six wells are scheduled to flowback on a

rotational basis to recover completion fluids and prepare for the installation of permanent surface facilities

1)See Advisories Appendix – Oil and Gas Measures and Definitions. CGRs stated are over a short period of time and are not necessarily indicative of long-term performance. Excludes days where wells did not produce.

Karr Pre D2 Wapiti Phase 1 Wapiti Post Phase 2 Karr Post D2 Wapiti Post Phase 3 Total Raw Gas Prod’n (MMcf/d) 79 56 112 126 146 CGR (Bbl/MMcf) 173 100 - 200 100 - 200 173 100 - 200 Total Sales (Boe/d) 25,000 13,500 - 18,700 27,000 - 37,300 40,000 35,100 - 48,500 % Liquids (%) 53% 38% - 55% 38% - 55% 53% 38% - 55% Illustrative Operating Netback ($/Boe) $25.00 $20.00 - $25.00 $20.00 - $25.00 $25.00 $20.00 - $25.00 Illustrative Total Operating Netback ($MM) $228 $99 - $170 $197 - $341 $365 $256 - $443

Drill to Maintain Production

Wells (#) 7 4 - 6 8 - 11 12 10 - 13 DCET Capex ($MM) ($89) ($49) - ($74) ($98) - ($135) ($152) ($123) - ($160) Incremental Annual FCF ($MM) $139 $49 - $97 $50 - $108 $74 $34 - $78 Illustrative Total Annual FCF ($MM) $139 $188 - $236 $238 - $344 $312 - $418 $346 - $496

Karr / Wapiti Free Cash Flow Potential

FCF Potential (1), (2) FCF Potential Build-up ($MM) (1), (2)

Karr and Wapiti together have the potential to generate annual free cash flow (1) of $350 MM - $500 MM.

• The table highlights illustrative potential annual free cash flow (1) (“FCF”) of Karr and Wapiti at various levels of

production based on the underlying assumptions set out below (2) 11

1) See Advisories Appendix - Non-GAAP Measures. 2) FCF based on a full year of prod’n; Wapiti sales volumes exclude NGLs; Wapiti type well sales volume assumed to remain unchanged at different CGRs; wells drilled and costs based on type well assumptions.

Although more geologically complex, the Montney Oil field continues to generate strong rates of return.

Kaybob Montney Oil Asset Overview

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Asset Overview

• Discovered in 2010 with ~150 wells drilled to date
• Paramount-owned 12-10 battery with 20,000 Bbl/d of

sour fluid handling capacity for treating

Recent Developments

• Four (4.0 net) new wells have been brought on production in

2019

• An appraisal well at Ante Creek was drilled, completed and

put on production in September

• Initial production results are encouraging and continue to

be evaluated

1) Based on management estimates and price deck. See Advisories Appendix – Type Well Information.

Return (%) 98% Payout (Months) 7 IP 365 (Boe/d) 391 Sales Volume (MBoe) 269

• Avg. Oil (%)

74% DCET ($MM) $4.6

Type Well Return (1)

Kaybob South Smoky Return (%) 13% 25% Payout (Months) 52 33 IP 365 (Boe/d) 673 462 Sales Volume (MBoe) 1,108 718

• Avg. CGR (Bbl/MMcf)

97 205 DCET ($MM) $12.3 $11.8

Asset Overview

• Liquids-rich Duvernay fairway controlled by a handful of

companies

• Increasing competitor activity de-risking Paramount lands
• Smoky Duvernay production flowing to Smoky 06-16 plant

(recently expanded to 12 MMcf/d) with multiple options for longer- term growth (100% WI)

Recent Developments

• Four (4.0 net) new wells brought on production at Kaybob Smoky

with an average cumulative CGR of 257 Bbl/MMcf (2)

• At Kaybob South, five (2.5 net) new wells on the 2-28 pad were

brought on production in late June 2019 with an average cumulative CGR of 158 Bbl/MMcf (2)

Kaybob Duvernay Asset Overview

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The most recent 4-well pad at Smoky continues to exceed expectations with a high liquids contribution in particular. 2019 activities will focus on Kaybob South.

1) Based on management estimates and price deck. See Advisories Appendix – Type Well Information. 2) See Advisories Appendix – Oil and Gas Measures and Definitions. CGRs stated are over a short period of time and are not necessarily indicative of long-term performance.

Type Well Return (1)

Cum Oil - All WG Duvernay Wells (Bbl)

Willesden Green Duvernay

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Asset Overview

• Material, contiguous Duvernay position at Willesden Green
• Majority of offsetting lands held by large cap producers and pure play

private companies that are increasing activity levels

• Paramount-owned Leafland gas plant with 22 MMcf/d of natural gas

processing capacity

Recent Developments

• The 5-29 Duvernay oil well at Willesden Green was completed and brought
• n production in Q3 2018
• Pressure test results indicate that an over-pressure, high oil

deliverability reservoir is present

• The well averaged 944 Boe/d of peak 30-day wellhead production (86%
• il) (1)

Paramount holds ~69,000 net acres of Duvernay rights at Willesden Green. A recent well has exhibited very encouraging results to date.

1) See Advisories Appendix – Oil and Gas Measures and Definitions. 2) Excludes Fee Title and Royalty lands.

Area Based Closures Reducing Cost Structure

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Paramount continues to focus on safety and environmental responsibility as it transitions into the abandonment and reclamation phase in both Hawkeye and Zama.

• Permanently shut-in dry gas production in Hawkeye in September 2018
• Paramount has completed the full shut-down of area production at Zama in northern Alberta, three

months ahead of schedule

• The closure program will continue into 2020 to permanently suspend all facilities and over 2,000

kilometers of pipeline

• Paramount received regulatory approval to move forward with its 2019 abandonment and reclamation

plan under the Area Based Closure (“ABC”) program introduced by the AER in September 2018

• This approval allows the Company to approach Abandonment and Reclamation Obligations (“ARO”)

in an efficient and cost effective manner by targeting efforts in a concentrated area

• First ABC program commenced at Hawkeye in the third quarter. Economies of scale under the ABC

program have resulted in significantly lower costs than prior estimates

• Paramount’s ARO budget of $32 MM for 2019 is in excess of the minimum spending target established by

the AER under the ABC program

• Paramount expects to continue to spend ~$30-$40 MM per year on ARO activities, including those at

Hawkeye and Zama

• Legacy asset dispositions accretive due to opex savings
• Permanent shut-in of uneconomic properties combined with ongoing non-core asset dispositions program

reduce both cost structure and G&A

• Closed the sale of certain natural gas weighted properties in West Central Alberta in December 2019

for cash consideration of ~$55 MM; assets generated a netback of ~$2.30/Boe in Q3/19 (1)

1) See Advisories Appendix - Non-GAAP Measures.

Montney Duvernay Grande Prairie Kaybob Kaybob Central Karr Wapiti Montney Oil Kaybob South Smoky Willesden Green

Return (%) 46% 45% 98% 13% 25% 48% Payout (Months) 21 15 7 52 33 19 IP 365 (Boe/d) 961 1,395 391 673 462 817 IP 365 CGR (2) (Bbl/MMcf) 209 111 79% 161 283 218 Sales Volume (MBoe) 1,481 1,594 269 1,108 718 1,327

• Avg. CGR (2) (Bbl/MMcf)

173 80 74% 97 205 113 DCET ($MM) $12.7 $12.3 $4.6 $12.3 $11.8 $13.2 Capital Efficiency ($/Boe/d) $13,217 $8,816 $11,797 $18,230 $25,584 $16,102 F&D ($/Boe) $8.58 $7.72 $17.15 $11.34 $16.88 $10.37 Lateral Length (m) 3,000 3,000 2,400 2,400 2,200 2,400 Tonnage (t/m) 2.5 2.5 0.4 3.5 3.0 3.5 Reliability (%) 93% 96% 95% 90% 90% 96%

1) Based on Management’s estimates and price deck. See the Advisories Appendix – Type Well Information. 2) Percent oil (%) for Montney Oil asset.

Type Well Economics - Core Areas

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Type Well Economics (1)

Paramount’s 2019 activities are predominantly directed to its highest risk-adjusted rate of return opportunities.

Paramount employed a consistent, methodical approach in developing its 2019 type curves

• Type well economics specifically relate to the 2019 operations Paramount is conducting with the exception of Smoky and Willesden

Green Duvernay which currently are not planned to be drilled in 2019

• Type curves were developed considering variables of reservoir/fluid quality, completion design/lateral length, and pad development,

and includes consistent approach to assess the early flowback, peak rate/initial decline, and late well life performance

Liquidity and Risk Management

Impact of Gas Market Diversification ($/Mcf)

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In Q4 2018, Paramount expanded its covenant based revolving bank credit facility to $1.5 billion. Market diversification strategies have improved netbacks.

Credit Facility

• Exercised accordion feature to expand credit facility from $1.2 billion to $1.5 billion in November 2018
• Extended maturity date to November 2022
• $720.9 MM drawn as at September 30, 2019
• Interest rate swaps in place to fix underlying rates on $500 MM of notional amount

Oil Hedges

• Paramount has 16,000 Bbl/d of liquids hedged for the remainder of 2019 at an average price of $78.05/Bbl and 4,000 Bbl/d

hedged for fiscal 2020 at an average price of $80.11/Bbl

• Sold 2019 WTI call options for 2,000 Bbl/d at an

exercise price of C$82.00/Bbl

Gas Sales Diversification Strategy

• Arrangements in place to sell ~60,000 GJ/d at

Dawn and ~22,000 GJ/d at Malin

• Contracts in place for firm export transport to

Dawn and Malin

• An additional 40,000 GJ/d of gas sales priced in

the US Midwest

AECO Physical Contracts

• The Company has AECO fixed-price physical sales

contracts to sell 50,000 GJ/d of natural gas at $2.36/GJ for winter 2019/2020 and 80,000 GJ/d of natural gas at $1.61/GJ for summer 2020

Strategic and Long-Term Investments

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

Paramount Investment Attributes

Extensive portfolio of liquids-rich resource plays in the Montney and Duvernay Returns focused capital allocation strategy supported by rigorous full-cycle

analysis

Aligned management and board with significant insider ownership Increasing proportion of condensate and oil production to drive revenue

growth

Methodical approach to ARO coupled with legacy asset dispositions reducing

cost structure

Strong liquidity position Returning capital to shareholders in the form of share buybacks

Paramount offers a unique investment proposition.

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Advisories Appendix

Advisories

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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) projected production and sales volumes (and the liquids component thereof); (ii) type well characteristics and forecast rates of return; (iii) planned capital expenditures (including the plays and activities in respect of which this capital is expected to be spent); (iv) planned abandonment and reclamation expenditures in 2019 and future years; (v) the expected timing of the start up of the 6-18 facility expansion; (vi) expected increases in sales volumes in the fourth quarter of 2019; (vii) the development potential and future production capacity of the Karr and Wapiti properties; (viii) the expectation that Karr will generate free cash flow in 2019; (ix) exploration, development and associated operational plans and strategies (including planned drilling and completion programs and the timing thereof, facility expansions and potential increases in processing, takeaway and related capacities); (x) the expected diminishment of the impact of commissioning activities at the Wapiti plant; (xi) the expectation that Wapiti will generate free cash flow in 2020 upon completion

• f ramp up; (xii) future processing and take away capacity at Wapiti and Karr; (xiii) estimated numbers of drilling locations; (xiv) the potential of Karr and Wapiti to generate significant free cash

flow in the future and the potential amounts thereof; and (xv) 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

• ther assumptions identified in this presentation or Paramount’s continuous disclosure documents: (i) future natural gas and liquids prices; (ii) royalty rates, taxes and capital, operating,

processing, transportation, general & administrative and other costs; (iii) foreign currency exchange rates and interest rates; (iv) general economic, market and business conditions; (v) the ability

• f Paramount to obtain the required capital to finance its exploration, development and other operations and meet its commitments and financial obligations; (vi) 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; (vii) the ability of Paramount to secure adequate product processing, transportation, de-ethanization, fractionation and storage capacity on acceptable terms; (viii) the ability of Paramount to market its natural gas and liquids successfully to current and new customers; (ix) the ability of Paramount and its industry partners to obtain drilling success (including in respect of anticipated production volumes, reserves additions, liquids yields and resource recoveries) and operational improvements, efficiencies and results consistent with expectations; (x) the performance of wells and facilities; (xi) the timely receipt of required governmental and regulatory approvals; (xii) the application of laws and regulations, including environmental laws; (xiii) the geological characteristics of the Company’s properties; and (xiv) anticipated timelines and budgets being met in respect of drilling programs, facility construction 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. 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 natural gas and liquids prices; (ii) changes in foreign currency exchange rates and interest rates; (iii) the uncertainty of estimates and projections relating to future revenue, future production, reserve additions, liquids yields (including condensate to natural gas ratios), capital expenditures, resources recoveries, well performance, royalty rates, taxes and costs and expenses; (iv) the ability to secure adequate product processing, transportation, de-ethanization, fractionation and storage capacity on acceptable terms; (v) operational risks in exploring for, developing and producing natural gas and liquids; (vi) the ability to obtain equipment, services, supplies and personnel in a timely manner and at an acceptable cost; (vii) potential disruptions or unexpected technical or other difficulties in designing, developing, expanding or operating new, expanded or existing facilities (including third-party facilities); (viii) processing, pipeline, de-ethanization, and fractionation infrastructure outages, disruptions and constraints; (ix) risks and uncertainties involving the geology of oil and gas deposits; (x) the uncertainty of reserves estimates; (xi) general business, economic and market conditions; (xii) the ability to generate sufficient cash flow from operations and obtain financing to fund planned exploration, development and operational activities and meet current and future commitments and obligations (including product processing, transportation, de-ethanization, fractionation and similar commitments and obligations); (xiii) changes in, or in the interpretation of, laws, regulations or policies (including environmental laws); (xiv) the ability to obtain required governmental or regulatory approvals in a timely manner and to obtain and maintain leases and licenses; (xv) the effects of weather and other factors, including wildlife and environmental restrictions which affect field operations and access; (xvi) uncertainties regarding the timing and costs

• f future abandonment and reclamation obligations and potential liabilities for environmental damage and contamination; (xvii) uncertainties regarding aboriginal claims and in maintaining

relationships with local populations and other stakeholders; (xviii) the outcome of existing and potential lawsuits, regulatory actions, audits and assessments; (xix) 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, 2018, which is available under the Company’s profile on SEDAR at www.sedar.com. The forward-looking information and statements contained in this presentation are made effective as of December 5, 2019. The type well information contained in this presentation has been prepared effective March 1, 2019, except where otherwise noted, and the drilling location information contained in this presentation was prepared effective January 1, 2019. In each case, events

• r information subsequent to the applicable effective dates have not been incorporated.

Advisories (con't)

22

Oil and Gas Measures and Definitions The term "liquids" includes oil, condensate and Other NGLs (ethane, propane and butane). NGLs consist of condensate and Other NGLs. Liquids Natural Gas Oil Equivalent Bbl Barrels Mcf Thousands of cubic feet Boe Barrels of oil equivalent MBbl Thousands of barrels Bcf Billions of cubic feet MBoe Thousands of barrels of oil equivalent Bbl/d Barrels per day MMcf/d Millions of cubic feet per day MMBoe Millions of barrels of oil equivalent NGLs Natural gas liquids GJ Gigajoule Boe/d Barrels of oil equivalent per day Condensate Pentane and heavier hydrocarbons This presentation 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, 2019, the value ratio between crude oil and natural gas was approximately 53:1. 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 presentation contains metrics and terms commonly used in the oil and natural gas industry. The metrics and terms are are “CGR”, “IP 365“, “Sales Volumes”, “DCET”, “Capital Efficiency”, “F&D” and “Reliability”. Each of these metrics and terms is determined by the Company as set out below under the heading “Type Well Information”. These metrics and terms 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 oil and gas metrics and terms for its own performance measurements and to provide shareholders with measures to compare the Company's performance over time; however, such measures are not reliable indicators 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. References are made in this presentation to “peak 30-day wellhead production” rates, which represent raw production volumes measured at the wellhead prior to shrinkage. Such production rates are stated 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. References to cumulative CGR reflect results up to October 31, 2019. 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 6, 2019 and effective December 31, 2018 (the “McDaniel Report”). The price forecast used in the McDaniel Report is an average of the January 1, 2019 price forecasts for McDaniel and GLJ Petroleum Consultants Ltd. and the December 31, 2018 price forecast of Sproule Associates Ltd. The estimates of reserves contained in the McDaniel Report and referenced in this presentation 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 presentation. There is no assurance that the forecast prices and costs assumptions used in the McDaniel Report will be attained, and variances could be material. Readers should refer to the Company's annual information form for the year ended December 31, 2018, which is available on SEDAR at www.sedar.com, for a complete description of the McDaniel Report and the material assumptions, limitations and risk factors pertaining thereto.

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Type Well Information The type well information contained in this presentation has been prepared effective March 1, 2019 by internal qualified reserves evaluators from Paramount using pricing of US$55/Bbl WTI, US$2.75/MMBtu NYMEX and $1.51/Mcf AECO and an exchange rate of US$0.760 for one Canadian dollar. The type well information for Karr has been updated effective June 27, 2019 to reflect the sale of the 6-18 Facility to CSV and the related midstream services agreement. The type well information 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 type well information contains no adjustments or assumptions respecting future facility and transportation constraints or outages. The forecast economics associated with type wells 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 type well information 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 “Return”, “CGR”, “IP 365“, “Total Sales Volumes”, “DCET”, “Capital Efficiency”, “F&D” and “Reliability” are used in presenting type well information. “Return” means the internal rate of return. “CGR” means condensate to gas ratio and is calculated by dividing raw Wellhead Liquids volumes by raw wellhead natural gas volumes. “Wellhead Liquids” means oil, condensate and other hydrocarbon liquids. “IP 365” means the estimated average daily sales volumes of production over the initial 365 days of production. “Sales Volumes” means the estimated aggregate potential sales volumes of production. “DCET” means the estimated drilling, completion, equipping and tie-in costs. “Capital Efficiency” represents the estimated cost per boe/d of production and is calculated by dividing DCET by IP 365. “F&D” means finding and development costs and is calculated by dividing DCET by Sales Volumes. “Reliability” means the percentage of time that a well is producing. The type well information 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. Type well information 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, 2018, which is available on SEDAR at www.sedar.com, for reserves information respecting the Company. The type curve forecasts used by McDaniel in preparing the McDaniel Report differ from those used to prepare the type well information contained in this presentation. The type well information presented herein does not have any standardized meaning and may not be comparable to similar measures presented by other companies. Actual results will vary from the type well information and such variations may be significant. Drilling Locations This presentation contains information respecting future potential drilling locations, referred to as “inventory”, at Karr and Wapiti. The drilling location information contained in this presentation was prepared effective January 1, 2019 by internal qualified reserves evaluators from Paramount. Of the 250+ drilling locations at Karr, 100 proved plus 32 probable locations (132 total proved plus probable) were assigned reserves in the McDaniel Report. Of the 250+ drilling locations at Wapiti, 82 proved plus 19 probable locations (101 total proved plus probable) were assigned reserves in the McDaniel Report. The drilling 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 drilling locations and there is no certainty that such locations will result in additional reserves or production. The drilling 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 drilling 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.

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Non-GAAP Measures In this presentation, “net debt", “netback“ and “free cash flow, collectively the "Non-GAAP measures", are used and do not have any standardized meanings as prescribed by International Financial Reporting Standards. “Free cash flow” equals netback from a particular property over a period less capital expenditures for such property in such period. The free cash flow measure provides management and investors with information regarding whether netback generated from the operations of a property exceeds capital amounts invested. This presentation states an expectation that Karr will continue to generate free cash flow in 2019 and an expectation that Wapiti will generate free cash flow in 2020 upon completion of ramp up. Such expectations are based on a number of assumptions, including capital expenditures at Karr and Wapiti in 2019 equaling base budgeted expenditures, wells performing in accordance with management’s estimated type curves, assumed commodity prices equivalent to those used in the type well information and management’s estimates as to royalties, operating costs, transportation costs and processing costs. This presentation also contains a table illustrating the potential of the Karr and Wapiti properties to generate free cash flow in the future based on the assumptions set out therein. Such information has been provided only to inform readers of management’s estimate of the future potential of the Karr and Wapiti properties to generate free cash flow and is not appropriate for use for other

• purposes. Such information is forward-looking information and readers should refer to the “Forward-Looking Information” section of these Advisories, including for a description of the risks and

uncertainties which could cause actual results to differ materially from the stated expectations respecting free cash flow at Karr and Wapiti. "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. The following is the calculation of net debt from the nearest GAAP measure as at September 30, 2019:

"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. Refer to the Operating Results section of the Company’s Management’s Discussion and Analysis for the year ended December 31, 2018 for the calculation of Paramount’s 2018 netback. The table below sets out the calculation of the netback of the Karr Property for the year ended December 31, 2018. Non-GAAP 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 measures are unlikely to be comparable to similar measures presented by other issuers.

Netback

($ millions) Petroleum and natural gas sales 349.3 Royalties (22.3) Operating expense (75.0) Transportation and NGLs processing (27.8) 224.2 ($ millions) Cash and cash equivalents (11.1) Accounts receivable (91.9) Prepaid expenses and other (16.4) Accounts payable and accrued liabilities 176.4 Adjusted w orking capital deficit (1) 57.0 Paramount bank credit facility 720.9 Net Debt 777.9

(1 ) Adjusted working capital excludes risk management assets and liabilities, current accounts receivable amounts relating to subleases (September 30, 201 9 - $2.1 million) and the current portion of asset retirement obligations, lease liabilities and other.