Corporate Presentation

Transcription

1 Corporate Presentation March 2019

2 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. 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. 2

3 Production (Boe/d) Corporate Overview Founded in 1976 (IPO d in 1978), Paramount has a proven track record and strategy that generates above-average long term rates of return. 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 Paramount Market Snapshot Quarterly Production Outlook Range (Boe/d) Ticker Symbol - TSX POU 92,000 Share Count MM 90,000 90,000 Market ~$980 MM 88,000 38% Liquids Net Debt (1) $896 MM 86,000 85,000 Enterprise Value ~$1.9 Bln 84,000 85,000 Insider Ownership (2) ~46% 1P Reserves (3) MMBoe 2P Reserves (3) MMBoe 82,000 80,000 78,000 37% Liquids 81,000 37% Liquids 80,000 80,000 H1 2019F Q3 2019F Q4 2019F 1) At December 31, 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. 3

4 Montney and Duvernay Focus Areas Paramount is forecasting 2019F production of 81,000 to 85,000 Boe/d. and Duvernay account for ~45,000 Boe/d of this. The Montney (1) (1) 1) Excludes production from the Resthaven / Jayar asset that was sold in

5 Paramount Strategy 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 Paramount Portfolio of Assets 2019 Type Well Rate of Return (%) (1) 1) Based on Management s estimates and price deck. See the Advisories Appendix Type Well Information. 5

6 Historical CFROCE (%) Historical CFROCE (%) Historical ROCE (%) History of Generating Returns The 2019 capital expenditure program is heavily weighted towards our highest return projects and is expected to drive and maintain strong returns on a go-forward basis. Paramount outperformed its peer group on return metrics in the last three and five years Reflects successful track record of monetizing assets well in excess of book value Return on Average Capital Employed ( ROCE ) defined as Return divided by Average Capital Employed (1) Cash Flow Return on Capital Employed ( CFROCE ) defined as Cash Flow divided by Average Capital Employed (1) Paramount vs. Peers - Historical CFROCE (%) (1) 55% 50% 45% 40% 35% 30% 25% 20% 15% 10% 5% - Ranked by 3-Yr Avg. POU Yr Avg 5-Yr Avg 140% 120% 100% 80% 60% 40% 20% - Paramount Historical CFROCE (%) (1) Sale of Oil Sands Assets Sale of U.S. Assets Musreau Sale (2) '07 '08 '09 '10 '11 '12 '13 '14 '15 '16 '17 '18 3-Yr 5-Yr Avg Avg 25% 20% 15% 10% 5% - (5%) (10%) Paramount vs. Peers - Historical ROCE (%) (1) Ranked by 3-Yr Avg Yr Avg 5-Yr Avg POU ) Refer to the heading Non-GAAP Measures in the Advisories Appendix. 2) Sale of midstream and upstream assets. 6

7 Capex ($MM) 2019 Budget and Production Guidance Paramount has set a base 2019 capital budget of $350 MM to support annual production of 81,000 85,000 Boe/d; 4Q19 forecast to average 85,000 90,000 Boe/d. 2019F Budget and Production Guidance F Production (Boe/d) 85,941 81,000-85,000 Liquids (%) 37% 38% Capex ($MM) $569 $350 ARO ($MM) $29 $32 Capital budget down ~40% vs program (1) $400 $350 $ F Capex Breakdown ($MM) (1) Corporate (2%) Central (5%) Other (9%) Kaybob (20%) Duvernay (10%) Corporate (2%) Maintenance (10%) Facility (14%) Prioritizing lower-risk and higher return, liquidsrich Montney plays with the tie-in of 20 wells at Karr and Wapiti $250 5 well completions at Kaybob South Duvernay $200 3 well Montney Oil program Minor capex for emerging play land retention The $350 MM budget excludes capital to advance the Karr 6-18 facility expansion ( D2 ) $150 $100 Grande Prairie (73%) Montney (81%) Complete (56%) Evaluating funding alternatives for $145 MM 2019F incremental spend Sales volumes are expected to increase in the second half of 2019F as Wapiti ramps up $50 - Drill (18%) Region Play Type Category 1) Base 2019 capital budget, excluding land acquisitions and abandonment and reclamation. 7

8 Karr Asset Overview 4Q18 Karr liquids debottlenecking activities were successfully completed with sales averaging 26,282 Boe/d vs. 21,636 Boe/d in the first nine months of 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 Type Well (1) Montney well in 2018 with results on par with the Middle Montney Return (%) 64% Two of the 2019 wells are targeting Payout (Months) 18 the Lower Montney IP365 (Boe/d) 961 Will incorporate results to Sales Vol. (MBoe) 1,481 determine inventory count Avg. CGR (Bbl/MMcf) 173 Generated 2018 netback of ~$224 MM on capex of ~$169 MM and is DCET ($MM) $12.7 expected to continue generating free cash flow in 2019 (2) Type well drilling inventory can sustain greater than 40,000 Boe/d of production (post D2) for nearly two decades from the Middle Montney alone Middle Montney Development Potential (1) Karr Middle Montney Type Well Inventory (#) >250 Type Well Raw Gas Vol. (Bcf) 4.0 Calculated Recovered Gas (Bcf) >1,000 Current Raw Gas Production Capacity (Mcf/d) 100,000 Implied Number of Years of Production (Years) ~27 Raw Gas Production Capacity Post D2 (Mcf/d) 150,000 Implied Number of Years of Production (Years) ~18 1) Based on management estimates and price deck. See Advisories Appendix Type Well Information. 2) See Advisories Appendix - Non-GAAP Measures. 8

9 Karr Asset Overview (Cont d) Processing and takeaway capacity is in place to support Montney growth at Karr. Recent Developments In 2018, the 1-2 five well pad was drilled, completed and brought on production and the 4-24 five well pad was drilled Completed, ahead of schedule and under budget, a number of facilities enhancements at the 6-18 facility in Q Debottlenecked liquids handling processes Expanded natural gas compression capacity from 80 MMcf/d to 100 MMcf/d As a result, facility reliability in Q exceeded 98% and sales volumes averaged 26,282 Boe/d Gas Processing and Takeaway Capacity Gross Capacity Current Post D2 Sour Raw Compression / Dehy (MMcf/d) Sour Raw Gas Processing (MMcf/d) - 70 Total Raw Gas Handling (MMcf/d) Raw Hydrocarbon Liquids Handling (Bbl/d) 15,000 30,000 Implied Capacity (Bbl/MMcf) Raw Water Handling (Bbl/d) 15,000 28,000 Sales Gas Takeaway (MMcf/d) ~65 ~ Capital Program Complete and tie-in the 4-24 five well pad drilled in 2018, and drill, complete and tie-in a three well pad at 1-19 to fully utilize available capacity at the existing 6-18 facility Complete and equip water disposal well and infrastructure D2 Facility Expansion D2, which could be completed in 2020, would add 70 MMcf/d of raw natural gas processing capacity and an additional 15,000 Bbl/d of raw liquids handling capacity Currently evaluating funding alternatives for the $145 MM of 2019F incremental spend 9

10 Wapiti Asset Overview Wapiti remains on track to come onstream in mid-2019 and is expected to meaningfully increase sales volumes in the second half of The Wapiti asset is a continuation of Karr and is characterized by multi interval potential in the Montney All three intervals have been tested Wapiti is expected to generate free cash flow starting in 2020 upon completion of ramp up (2) Type Well (1) Return (%) 45% Payout (Months) 15 IP365 (Boe/d) 1,395 Sales Vol. (MBoe) 1,594 Avg. CGR (Bbl/MMcf) 80 DCET ($MM) $12.3 Type well drilling inventory can sustain over 40,000 Boe/d of production for over 20 years, based on Paramount s highgraded 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 Middle & Lower Montney Development Potential (1) Wapiti Montney Type Well Inventory (#) >250 Type Well Raw Gas Vol. (Bcf) 5.0 Calculated Recovered Gas (Bcf) >1,250 Wapiti Plant Phase 1 Capacity (Mcf/d) 150,000 Implied Number of Years of Production (Years) ~23 1) Based on management estimates and price deck. See Advisories Appendix Type Well Information. 2) See Advisories Appendix - Non-GAAP Measures. 10

11 Wapiti Asset Overview (Cont d) Processing and takeaway capacity is in place to support Montney growth at Wapiti, with natural gas sales takeaway increasing to 130 MMcf/d by Recent Developments Large scale development of Wapiti has commenced in earnest with first production expected by mid-2019 Paramount is the anchor tenant in a 150 MMcf/d gas plant (expanding to 300 MMcf/d) that is expected to be operational by mid-2019 In 2018, 11 wells on the 9-3 pad were drilled and completed 2019 Capital Program The drilling of the wells on the 5-3 pad are scheduled to be finished by the end of Q Paramount will gradually bring wells from the 9-3 pad on production following the start-up of the Wapiti plant Wells from the 5-3 pad will be completed and also brought on production later in 2019, as required Gas (MMcf/d) Gas Processing and Takeaway (MMcf/d) Gold Creek Node (Raw Gas) Wapiti Plant Paramount Capacity (Raw Gas Processing) Takeaway Capacity (Sales Gas) - Jan-19 Jan-20 Jan-21 11

12 Kaybob Montney Oil Asset Overview Although more geologically complex, the Montney Oil field continues to generate strong rates of return. Asset Overview Discovered in 2010 with ~150 wells drilled to date Paramount owned battery with 20,000 Bbl/d of sour fluid handling capacity for treating Recent Developments 12 wells were drilled and completed in 2018 of which 10, plus a well drilled in late 2017, were brought on production in Capital Program Remaining two wells from 2018 were brought on production and three new wells will be drilled, completed and brought on production Type Well Return (1) Return (%) 98% Payout (Months) 7 IP365 (Boe/d) 391 Sales Vol. (MBoe) 269 Avg. Oil (%) 74% DCET ($MM) $4.6 1) Based on management estimates and price deck. See Advisories Appendix Type Well Information. 12

13 Kaybob Duvernay Asset Overview The recent 4-well pad at Smoky continues to exceed expectations with high liquids contribution in particular activities will focus on Kaybob South. 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 6-16 plant (recently expanded to 12 MMcf/d) with multiple options for longer-term growth (100% WI) Recent Developments The 7-22 five well pad (51% WI) at Kaybob South and the Smoky four well pad (100% WI) were brought on production in H Capital Program The five well 2-28 pad at Kaybob South commenced drilling last year and will be completed and brought on production in mid-2019 Type Well Return (1) Kaybob South Smoky Return (%) 13% 25% Payout (Months) IP365 (Boe/d) Sales Vol. (MBoe) 1, Avg. CGR (Bbl/MMcf) DCET ($MM) $12.3 $11.8 1) Based on management estimates and price deck. See Advisories Appendix Type Well Information. 13

14 Cum Oil (MBbl) Central Alberta & Other Overview Multiple land and resource positions including ~150,000 net acres of core Duvernay rights at Willesden Green and the East Shale Basin. Asset Overview Low decline, predictable production Owned and operated gas processing facilities Material, contiguous Willesden Green Duvernay position Recent Developments The 5-29 Duvernay oil well at Willesden Green was completed and brought on production in Q 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% oil) (1) 160, ,000 Cum Oil - All WG Duvernay Wells (MBbl) 120, ,000 80,000 60,000 40,000 The 5-29 well (shown in red) is the 20,000 best performing Duvernay oil well in Willesden Green to date Normalized Flowing Months 1) See Advisories Appendix Oil and Gas Measures and Definitions. 14

15 Area Based Closures Reducing Cost Structure 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 also decided to cease operations in the Zama field in northern Alberta Accretive to funds flow as both properties had negative netbacks in 2018 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 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 15

16 Type Well Economics - Core Areas Paramount s 2019 activities are predominantly directed to its highest risk-adjusted rate of return opportunities. Type Well Economics (1) Montney Duvernay Grande Prairie Kaybob Kaybob Central Karr Wapiti Montney Oil Kaybob South Smoky Willesden Green Return (%) 64% 45% 98% 13% 25% 48% Payout (Months) IP365 (Boe/d) 961 1, IP365 CGR (2) (Bbl/MMcf) % Sales Volume (MBoe) 1,481 1, , ,327 Avg. CGR (2) (Bbl/MMcf) % 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) Reliability (%) 93% 96% 95% 90% 90% 96% 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 1) Based on Management s estimates and price deck. See the Advisories Appendix Type Well Information. 2) Percent oil (%) for Montney Oil asset. 16

17 Gas Revenue ($/Mcf) Liquidity and Risk Management 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 $815 MM drawn as of December 31, 2018 Recently entered into interest rate swaps to fix underlying rates on $500 MM of notional amount Oil Hedges 14,000 Bbl/d of oil hedged at WTI of C$77.05/Bbl for 2019 Sold 2019 WTI call options for 2,000 Bbl/d at an exercise price of C$82.00/Bbl Gas Sales Diversification Strategy Arrangements in place to sell ~60,000 GJ/d at Dawn and ~21,000 GJ/d at Malin Contracts in place for firm export transport to Dawn and Malin An additional 40,000 GJ/d of gas sales priced in the US Midwest Impact of Gas Market Diversification ($/Mcf) $3.00 AECO Sales Price Uplift from Diversification $2.50 $0.46 $0.80 $2.00 $0.54 $1.50 $0.48 $1.00 $2.13 $1.93 $0.50 $1.23 $ Q Q Q Q

18 Strategic and Long-Term Investments Paramount is unique in that it holds a strategic position in a number of public and private entities. 18

19 Investment Attributes Paramount offers a unique investment proposition. 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 19

20 Advisories Appendix

21 Advisories 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) and the expectation that 2019 capital expenditures will drive and maintain strong returns; (iv) planned abandonment and reclamation expenditures in 2019 and future years; (v) estimated capital expenditures required to advance the 6-18 facility expansion; (vi) expected increases in sales volumes in the second half 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, facility expansions and potential increases in processing, takeaway and related capacities); (x) expected increases to sales volumes from Wapiti production in 2019; (xi) the expectation that Wapiti will generate free cash flow in 2020 upon completion of ramp up; (xii) future processing and take away capacity at Wapiti and Karr; (xiii) the expected timing of first production at Wapiti and a new third party gas plant at Wapiti becoming operational; (xiv) estimated numbers of drilling locations; 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 other 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 of 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 of 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; and (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 The forward-looking information contained in this presentation is made as of the date hereof and, except as required by applicable securities law, Paramount undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise. 21

22 Advisories (con't) 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 year ended December 31, 2018, the value ratio between crude oil and natural gas was approximately 47:1. 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. 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 for a complete description of the McDaniel Report and the material assumptions, limitations and risk factors pertaining thereto. 22

23 Advisories (con't) 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 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 wellhead raw liquids volumes by wellhead raw natural gas volumes. 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 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. 23

24 Advisories (con't) Non-GAAP Measures In this presentation, adjusted funds flow, net debt", netback, free cash flow", ROCE and CFROCE, collectively the "Non-GAAP measures", are used and do not have any standardized meanings as prescribed by International Financial Reporting Standards. Adjusted funds flow refers to cash from operating activities before net changes in operating non-cash working capital, geological and geophysical expenses, asset retirement obligation settlements and transaction and reorganization costs. Adjusted funds flow is commonly used in the oil and gas industry to assist management and investors in measuring the Company s ability to fund capital programs and meet financial obligations. Refer to the Consolidated Results section of the Company s Management s Discussion and Analysis for the year ended December 31, 2018 for the calculation of adjusted funds flow. 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. 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. Refer to the Liquidity and Capital Resources section of the Company s Management s Discussion and Analysis for the year ended December 31, 2018 for the calculation of net debt as at December 31, "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 and 2017 netback. The table below sets out the calculation of the netback of the Karr Property for the year ended December 31, Netback ($ millions) Petroleum and natural gas sales Royalties (22.3) Operating expense (75.0) Transportation and NGLs processing (27.8) ROCE means return on average capital employed and is determined by dividing: (i) net income plus interest and financing expense (tax affected), by (ii) average Capital Employed. CFROCE means cash flow return on capital employed and is determined by dividing: (i) adjusted funds flow plus interest and financing expense, plus cash proceeds from dispositions of assets (including debt assumed by purchasers) and less asset retirement obligations settled, by (ii) average Capital Employed. Capital Employed equals total assets less current liabilities. The ROCE and CFROCE measures allow management and others to evaluate the Company s returns by measuring earnings or cash flows relative to the capital employed in the business. The peer group employed for the purposes of the charts set out under History of Generating Returns in this presentation consists of ARX, BIR, NVA, TOU and VII. 3 and 5 year averages of ROCE and CFROCE presented are simple averages of annual returns. 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. 24