Corporate Presentation

Transcription

1 Corporate Presentation July 2018

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. Any use of information contained in this presentation is expressly forbidden. 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. 2

3 Corporate Overview Founded in 1976; IPO in 1978; TSX: POU Market Cap: ~$2.0 Bln (132.8 MM Insider ownership: ~46% Pro Forma Net Debt: ~$536 MM (1) Total land position ~3.0 million net acres including: ~330,000 net Montney acres ~230,000 net Duvernay acres 376 MMBoe Proved Reserves; 593 MMBoe P+P Reserves as of December 31, 2017 (2) 443 P+P undeveloped locations plus ~2,100 P+P high grade internal locations (2) Q Results Q Production Q Capex Q Opex 92,203 Boe/d (~37% Liquids) $136 MM $11.12 / Boe 2018 Guidance 2018E Production 2018E Capex 2018E Opex ~90,000 Boe/d (~37% Liquids) ~$600 MM ~$11.00 / Boe 1) Net Debt at March 31, 2018 less $170 MM cash proceeds from the Resthaven/Jayar property sale received July Refer to the heading Non-GAAP Measures in the Advisories Appendix. 2) Refer to the heading Reserves and Other Information in the Advisories Appendix. 3

4 Highlights Transaction Highlights April 2016 sold Musreau Plant ~$565 MM August 2016 sold Musreau Asset ~$2.1 Bln December 2016 sold royalty on Cavalier oil sands assets for ~$100 MM May 2017 closed the sale of Valhalla assets for cash of ~$150 MM August 2017 closed Apache Canada acquisition for ~$487 MM September 2017 merged with Trilogy for 1 POU share for every 3.75 TET shares July 6, 2018 closed the sale of Resthaven/Jayar assets for ~$340 MM Operating Highlights Organic growth in Paramount Legacy production from Q ~16,000 Boe/d to >35,000 Boe/d by year end 2017 Karr completions improvements have resulted in improved productivity and liquids yields that are exceeding expectations The Company has sanctioned the construction of a new processing facility that will add 50 MMcf/d of natural gas processing capacity and 30,000 Bbl/d of condensate stabilization capacity to be built alongside the Karr 6-18 facility; commissioning expected in H

5 Higher Sales & Stronger Balance Sheet Organically grew legacy Paramount production from ~11,000 Boe/d following the Musreau sale to ~37,000 Boe/d in October 2017 through the Karr development program Returned to pre-disposition production levels in 14 months 5

6 Strategic Transactions ~$487 MM acquisition; funded with cash on hand High quality Wapiti Montney acreage, liquids-rich Montney and Duvernay at Kaybob and lower decline, long-life assets in Central Alberta (including 183,000 net acres of fee simple lands) Added ~39,000 Boe/d of production (26% liquids), ~283 MMBoe of proved plus probable reserves (1) Profitable growth while creating and delivering real value for all stakeholders ~$1.1 Billion (2) merger; issued ~28.5 MM Paramount common shares Lower decline, high netback, Montney oil and gas plays and highly economic, condensate-rich Kaybob Duvernay plays producing through operated infrastructure Added ~22,000 Boe/d of production (36% liquids), ~157 MMBoe of proved plus probable reserves (1) (1) Sales volumes for the three months ended June 30, Reserves volumes as per McDaniel & Associates Consultant Ltd. report dated December 31, Refer to the heading Reserves and Other Information in the Advisories Appendix. (2) Represents transaction value for the entirety of Trilogy (including Paramount s 15% ownership and debt of Trilogy); based on July 6, 2017 closing share price of Paramount and exchange ratio of one Paramount share for every 3.75 Trilogy shares. 6

7 Diversified Montney and Duvernay Assets Asset Description Stage of Development Location Inventory P+P Total (1) (1) Breakeven WTI Oil US$/Bbl (2) () Breakeven NYMEX Gas US$/MMbtu (2) () 2021 Wellhead Production Potential (Gross) Liquids Bbl/d Total Boe/d (3) Focus Assets Karr Montney Development ,000 43,000 (Phase 1) Wapiti Montney Development ,000 39,000 (Phase 1) Kaybob Montney Oil Development (1.54) 8,000 14,000 Kaybob South Duvernay Development ,000 21,000 Kaybob Smoky Duvernay Development (1.10) 13,000 23,000 Subtotal 384 1,095 61,000 Bbl/d 140,000 Boe/d Longer-Term Assets Ante Creek Montney Evaluation Analyzing long-term production results from new 6-well pad Presley/Fir Montney Gas Development Proven development: best developed when gas prices rise Birch Montney JV Development Analyzing results of the 2017 drilling program Kaybob North Duvernay Delineation Studying offset performance Kaybob Bigstone Duvernay Delineation 0 50 Studying offset performance Kaybob Pine Creek Duvernay Delineation 0 TBD Commercial potential from new completion learnings Willesden Green Duvernay Piloting Analyzing results from completion at 02/13-05 Hz. (1) Refer to the heading Reserves and Other Information in the Advisories Appendix. (2) Breakeven analysis discounted at 10 percent before tax, FX rate of $0.80 $US/$C, AECO basis of US$1.00/MMbtu and constant costs based on current cost structure. Breakeven gas prices based on a constant NYMEX gas price of US$3.00/MMbtu. Breakeven oil prices based on a constant WTI oil price of US$50.00/Bbl. (3) Wellhead production volumes are before surface losses and shrinkage. Liquids volumes refer to C5+ volumes only. 7

8 Grande Prairie Snapshot Operational Highlights 2018 Program: Drill two five-well pads at Karr; complete 1 pad Drill 23 wells; complete 6 wells at Wapiti Q Sales: 28,398 Boe/d (51% liquids) Asset Summary Resthaven/Jayar sold to Strath Resources Ltd. for ~$340 MM July 2018 Focused on Montney assets in Alberta Deep Basin trend - Wapiti and Karr Over-pressured liquids-rich natural gas Up to three development layers Midstream capacity in place for growth Grande Cretaceous Prairie upside Inventory across the Deep Basin trend ~107,000 net acres of Alberta Deep Basin Montney P+P inventory of 181 locations (1) P+P plus internal high grade inventory of 686 locations (1) (1) Refer to the heading Reserves and Other Information in the Advisories Appendix. 8

9 Karr Montney Asset Detail (1) Operational Highlights Wells on the 1-2 pad are drilled and completed; expected to produce Q Wells on the 4-24 pad are rig released and will be completed Q1 2019; expected to produce Q Average peak 30-day wellhead rate of 1,966 Boe/d (~60% condensate) from most recent 27 wells Asset Potential ~45,000 net acres of liquids-rich Montney rights P+P inventory of 69 locations plus over 200 internal high grade locations The Facility is being expanded from 80 MMcf/d to 100 MMcf/d for late 2018 Installing additional liquids loading equipment at the 6-18 facility and pad sites to increase trucking capacity Next growth phase to 150 MMcf/d in 2020 with new facility including 50 MMcf/d of gas processing and 30,000 Bbl/d of stabilization capacity (1) Refer to the heading Reserves and Other Information in the Advisories Appendix. 9

10 Karr Montney P+P Type-Well (1) Lateral Length = 3,000m Proppant Loading = 1,565 lb/ft (2.3 t/m) Stages = 75 Karr West Unit Wellhead IP30 Boe/d 2,112 Wellhead IP30 Condensate % 67 Total Sales Gas Bcf 4.8 Total Sales Condensate MBbl 569 Total Sales Volume MBoe 1,428 DCET (multi-well pad) MM$ 12.8 Btax NPV10 MM$ 10.4 Btax Return % 68 Payout Months 11 Lifetime CGR Bbl/MMcf 118 Lateral Length = 3,000m Proppant Loading = 1,565 lb/ft (2.3 t/m) Stages = 75 Karr East Unit Wellhead IP30 Boe/d 1,632 Wellhead IP30 Condensate % 54 Total Sales Gas Bcf 5.2 Total Sales Condensate MBbl 468 Total Sales Volume MBoe 1,410 DCET (multi-well pad) MM$ 12.8 Btax NPV10 MM$ 7.0 Btax Return % 47 Payout Months 16 Lifetime CGR Bbl/MMcf 96 Note: Includes 7 month spud to first production time and capital for gathering/compression nodes. (1) Based on Management s estimates. US$50/Bbl WTI & US$3.00/MMbtu NYMEX, US$1.00/MMbtu AECO Basis & FX US$/C$0.80. Refer to the heading Reserves and Other Information in the Advisories Appendix. 10

11 Wapiti Montney Asset Detail (1) Operational Highlights 9-3 pad drilling has begun (total 11 wells in 2018) Additional 12 wells to be drilled from 5-3 pad Third party gas plant and infrastructure under construction with scheduled Q in-service Paramount completion design on new wells Asset Potential ~49,000 net acres of liquids rich Montney Up to three development layers have been tested P+P inventory of 112 locations P+P plus internal high grade of >450 locations Paramount is anchor tenant in gas plant and infrastructure 150 MMcf/d expandable to 300 MMcf/d Delineation & Retention (Open Hole Packers) Zone Peak 24 Hr Test Rate (Wellhead) Boe/d (2) Condy % (Wellhead) (2) Proppant Intensity lb/ft 00/ W6 UM / W6 LM 1, / W6 UM 1, ,037 02/ W6 MM 1, / W6 MM 1, / W6 LM 1, ,325 00/ W6 LM 3, (1) Refer to the heading Reserves and Other Information in the Advisories Appendix. (2) Refer to the heading Test Results in the Advisories Appendix. 11

12 Wapiti Montney P+P Type-Well (1) Wapiti Unit Wellhead IP30 Boe/d 2,159 Wellhead IP30 Condensate % 56 Total Sales Gas Bcf 4.9 Total Sales Condensate MBbl 500 Total Sales Volume MBoe 1,408 DCET (multi-well pad) MM$ 12.5 Btax NPV10 MM$ 7.9 Lateral Length = 3,000m Proppant Loading = 1,676 lb/ft (2.5 t/m) Stages = 75 Btax Return % 54 Payout Months 16 Lifetime CGR Bbl/MMcf 102 Note: Includes 7 month spud to first production time and capital for gathering/compression nodes. 1) Based on Management s estimates. US$50/Bbl WTI & US$3.00/MMbtu NYMEX, US$1.00/MMbtu AECO Basis & FX US$/C$ Refer to the heading Reserves and Other Information in the Advisories Appendix. 12

13 Kaybob Snapshot (1) (1) Refer to the heading Reserves and Other Information in the Advisories Appendix. Operational Highlights 8 of 17 planned Montney wells have been drilled and put on production 9 of 14 planned Duvernay wells are rig released and expected to be on production in Q Evaluating gas re-routing projects to reduce operating costs Q Sales: 41,843 Boe/d (30% liquids) Asset Summary Three Montney assets and five Duvernay assets Montney assets includes oil at Ante Creek and Kaybob gas at Presley/Fir Duvernay assets range from volatile oil in Kaybob North to wet gas in Kaybob Pine Creek Company-owned natural gas processing capacity at Kaybob exceeds 200 MMcf/d, and the oil batteries can process more than 40,000 Bbl/d of liquids Kaybob Inventory 200,000 net acres of Kaybob & Ante Creek Montney 136,000 net acres of Kaybob Duvernay P+P inventory of 243 Cretaceous, Montney and Duvernay locations P+P plus internal high grade inventory of >900 locations 13

14 Kaybob Duvernay Asset Details (1) Operational Highlights Kaybob Smoky pad: 4 wells drilled and completed; expected to be brought on production Q Kaybob South 7-22 pad: 5 wells drilled and completed; recently on production Special projects include fibre optics and micro-seismic Kaybob South 2-28 pad: 5 wells planned Asset Potential ~136,000 core Kaybob Duvernay acres Development focus on Kaybob Smoky and Kaybob South P+P inventory of >100 locations P+P plus internal high grade >200 locations Kaybob Smoky Near-term production to Smoky Gas Plant with two options for longer-term growth including Kaybob Gas Plant and SemCAMs KA Kaybob South Existing 40 MMcf/d third party capacity from field to sales with expansion options for up to 40 MMcf/d of incremental capacity (1) Refer to the heading Reserves and Other Information in the Advisories Appendix. 14

15 Kaybob Duvernay P+P Type-Well (1) Lateral Length = ~ 2,700m Proppant Loading = 2,000 lb/ft (3.0 t/m) Kaybob Smoky Unit Wellhead IP30 Boe/d 1,877 Wellhead IP30 Condensate % 69 Total Sales Gas Bcf 2.2 Total Sales Condensate MBbl 469 Total Sales Volume MBoe 929 DCET (multi-well pad) MM$ 11.5 Btax NPV10 MM$ 8.2 Btax Return % 60 Payout Months 15 Lifetime CGR Bbl/MMcf 213 Kaybob South Unit Lateral Length = ~2,400m Proppant Loading = 2,350 lb/ft (3.5 t/m) Wellhead IP30 Boe/d 2,147 Wellhead IP30 Condensate % 62 Total Sales Gas Bcf 4.2 Total Sales Condensate MBbl 401 Total Sales Volume MBoe 1,303 DCET (multi-well pad) MM$ 11.9 Btax NPV10 MM$ 4.1 Btax Return % 29 Payout Months 25 Lifetime CGR Bbl/MMcf 95 1) Based on Management s estimates. US$50/Bbl WTI & US$3.00/MMbtu NYMEX, US$1.00/MMbtu AECO Basis & FX US$/C$ Refer to the heading Reserves and Other Information in the Advisories Appendix. 15

16 Kaybob Montney Oil Development (1) Operational Highlights 2018 activity: Eight of the 17 Montney horizontal wells planned are completed and on production New well design incorporates a higher number of frac stages and increased proppant intensity Asset Potential Discovered 2011 with ~150 wells drilled to date ~32,000 net acres P+P inventory of 100 locations with an additional 100 internal high grade locations Paramount Battery with 20,000 Bbl/d of sour fluid handling capacity Description Wells Average First 3 Months Oil volume/well On Production ,271 Bbl On Production ,325 Bbl On Production ,125 Bbl On Production 2014/ ,983 Bbl New Completion Design 2016/ ,218 Bbl Average P+P Type Well N/A 25,700 Bbl (1) Refer to the heading Reserves and Other Information in the Advisories Appendix. 16

17 Kaybob Montney Oil P+P Type Well (1) Kaybob Montney Unit Wellhead IP30 Boe/d 545 Wellhead IP30 Oil % 80 Total Sales Gas Bcf 0.6 Total Sales Oil/Condensate MBbl 154 Total Sales Volume MBoe 261 DCET (multi-well pad) MM$ 3.0 Btax NPV10 MM$ 2.2 Btax Return % 68 Payout Months 11 Completion Design Update New completion design has 30% more stages and 100% higher proppant loading intensity Acceleration of recoveries only (no incremental reserves), same design, and same cost 1) Based on Management s estimates. US$50/Bbl WTI & US$3.00/MMbtu NYMEX, US$1.00/MMbtu AECO Basis & FX US$/C$ Refer to the heading Reserves and Other Information in the Advisories Appendix. 17

18 Central Alberta & Other Snapshot (1) Operational Highlights 2018 Program: 1 hz Duvernay well rig released at Willesden Green 1 of 3 planned hz Glauconite wells at Leafland has been spud New well at 02/ W5 had a peak rate of 532 Bbl/d (total producing days 384) Q Sales: 21,962 Boe/d (32% liquids) Asset Summary Contiguous Willesden Green Duvernay position with 2x over-pressure oil fairway Large fee title land position across resource plays in Duvernay, Ellerslie, Glauconite, and Cardium Owned and operated gas processing facilities Central Alberta & Other Inventory ~128,500 net acres of Willesden Green and East Shale Basin Duvernay ~183,000 net acres of fee title lands ~93,000 net acres of core Ellerslie lands ~115,000 net acres of core Glauconite lands ~165,500 net acres of core Cardium lands (1) Refer to the heading Reserves and Other Information in the Advisories Appendix. 18

19 Willesden Green (1) Operational Highlights Horizontal well at 4-21 pad is rig released and expected to be completed and brought on production Q Asset Potential Duvernay Shale Play 59,686 acres of land (100% WI) Drilled and completed 4 Hz Duvernay wells to date 02/13-05 Cum Production to July 1, MMcf Gas 104,206 Bbl Oil (1) Refer to the heading Reserves and Other Information in the Advisories Appendix. 19

20 2018 Guidance 2018 Capex ~$600 million (excluding acquisitions & divestitures) Plan to drill ~70 development wells and complete ~42 of those wells 42 well completions represent ~11% of PRL s P+P undeveloped locations (1) Drilling services to be primarily provided by Paramount's wholly-owned Fox Drilling, which owns seven triple-sized rigs; the Company has contracted a dedicated frac unit for all of 2018 An additional $28 million budgeted for abandonment and suspension activities 17,000 Bbl/d of liquids hedged for the remainder of 2018 at C$71.61/Bbl WTI; 12,000 Bbl/d of liquids hedged for 2019 at C$75.36/Bbl WTI (2) Paramount has arrangements in place to transport and sell approximately 60,000 GJ/d of natural gas at the Dawn natural gas hub in Ontario ($US NYMEX ref prices) and 21,000 GJ/d of natural gas in California ($US Malin ref prices) 2018 Capital Allocation by Play (1) Based on McDaniel & Associates Consultants Ltd. reports as at December 31, (2) In Q1 2018, sold 2019 call options; 2,000 Bbl/d at C$82.00/Bbl 20

21 Midstream & Marketing Strategy Karr Kaybob North Keyera Wapiti Midstream Portfolio Positioned for Growth Takeaway capacity secured to manage Montney and Duvernay growth plan through 2021 Owned and operated infrastructure coupled with 3 rd party midstream provides balanced opex structure Opportunities to increase 3 rd party fee revenue from non-core infrastructure assets Firm, Reliable Market Access Secure firm service gas takeaway on TransCanada Pipeline ( TCPL ) capacity at receipt points in growth plays at Wapiti, Karr and Kaybob Majority of key gas processing facilities are dually connected to TCPL and Alliance Pushing Further Downstream Contracts for firm TCPL export transport to Dawn and Malin provide access to downstream markets Shipper status on both Pembina and Plains feeder pipelines allows for direct marketing of our products Own and operate a major Pembina-connected battery in Kaybob area which offers terminalling and blending opportunities 21

22 Indicative Revenue/Boe (1) Revenue WTI US$/Bbl NYMEX US$/mmbtu AECO C$/GJ BASIS US$/mmbtu FX PROPANE US$/Bbl BUTANE US$/Bbl ETHANE US$/Bbl C$/Boe 2018 Budget Spring Update (1.00) June 30, 2018 Strip (1.72) Oil/ Condensate 73% Oil/ Condensate 26,300 Bbl/d Natural Gas 19% NGL 8% Natural Gas 56,500 Boe/d NGL 7,200 Bbl/d 1) Before hedges 2) Based on June 30, 2018 strip prices 2018E Revenue (2) 2018E Production (90,000 Boe/d) 22

23 Strategic and Long-Term Investments (1) Please refer to the heading Reserves and Other Information in the Advisories Appendix. (2) Publicly disclosed by competitor. 23

24 The New Paramount Significantly Expanded Scale with Financial Flexibility Intermediate E&P company with an extensive portfolio of liquids-rich unconventional plays and the financial strength to exploit those opportunities Reserves: 149 MMBoe PDP, 376 MMBoe Proved, 593 MMBoe P+P (1) Strong Liquidity: $1.2 Billion 4-year revolving credit facility; expandable to $1.5 Billion (2) Low Leverage: Proforma Net Debt to Cash Flow of 1.4x (3) Pro forma net debt ~$536 MM (4) Diversified Asset Portfolio with Multiple Resource Plays Large inventory of repeatable drilling locations in multiple resource development projects Projects at various stages in the development lifecycle, from harvesting to piloting Cash flow from existing larger production base and free cash flowing projects to be redeployed into liquids-rich growth projects Greater proportion of lower decline production Opportunities to Realize Material Synergies Economies of scale and cost reductions through optimization of field teams, infrastructure and commercial contracts Consolidation of corporate organizations, systems, processes and G&A (1) Refer to the heading Reserves and Other Information in the Advisories Appendix. (2) Through the exercise of $300 MM accordion feature. (3) Using Q Cash Flow (Adjusted Funds Flow) annualized. Refer to the heading Non-GAAP Measures in the Advisories Appendix (4) Net Debt at March 31, 2018 less $170 MM proceeds from the Resthaven/Jayar property sale received July Refer to the heading Non-GAAP Measures in the Advisories Appendix 24

25 Appendix: Additional Information

26 Performance (1) As evaluated by McDaniel & Associates Consultants Ltd. as of December 31,

27 Paramount Completion Evolution Gen 1 Technology and Fluid: Lateral Length and Stage Spacing: Proppant Loading and Proppant Type: Cluster Spacing and Pump Rate: Open Hole Packers and Energized Oil Up to 1,600m and 100m (~16 stages) Up to 0.6 t/m (400 lbs/ft) and uniform sand size Single point entry up to 4 m3/min Gen 2 Technology and Fluid: Lateral Length and Stage Spacing: Proppant Loading and Proppant Type: Cluster Spacing and Pump Rate: Open Hole Packers and Energized Water Up to 2,600m and 80m (~32 stages) Up to 1.5 t/m (1,000 lbs/ft) and uniform sand size Single point entry up to 6 m3/min Gen 3 Technology and Fluid: Lateral Length and Stage Spacing: Proppant Loading and Proppant Type: Cluster Spacing and Pump Rate: Cased Hole (Combo Systems) and Slickwater Up to 3,000m and 40m (~75) stages Up to 2.5 t/m (1,700 lbs/ft) and multiple sand sizes Multi-point entry (down to 6m) and up to 14 m3/min Next Customized Cluster Design Plug Optimizations Enhanced Zipper Fracturing 100% Plug and Perf The goal is to achieve the best bang for our buck while optimizing condensate recoveries. 27

28 Focus Assets Btax 10% (1) (1) Breakeven analysis discounted at 10 percent before tax, based on internal type well assumptions using constant costs, FX rate of $0.80 $US/$C and AECO basis of US$1.00/MMbtu. Breakeven oil prices based on a constant NYMEX gas price of US$3.00/MMbtu. Breakeven gas prices based on a constant WTI oil price of US$50.00/Bbl. Refer to the heading Reserves and Other Information in the Advisories Appendix. 28

29 Advisories Appendix

30 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: projected production and sales volumes (and the liquids component thereof); forecast capital expenditures (including the plays and activities in respect of which this capital is expected to be spent); operating costs per BOE and abandonment and reclamation costs; estimated revenues per BOE under different pricing scenarios (and the portions of such revenues attributable to oil and condensate, other NGLs and natural gas production and the foreign exchange rate, royalty, transportation cost and operating expense assumptions used to generate these estimates); reserves estimates; exploration, development and associated operational plans and strategies (including planned drilling and completion programs, facility expansions and potential increases in third party processing and related capacities); estimated numbers of drilling locations (including high grade locations); the gross liquids and total production potential of each of the Company s main plays as well as the estimated break-even prices for production from, and the projected internal rates of return and discounted net present value of wells in, each of these areas; ongoing enhancements in Paramount s well completion techniques; the projected ability of the Company s existing midstream infrastructure and commitments to facilitate its Montney and Duvernay development plans through 2021; anticipated benefits from the acquisition of Apache and merger with Trilogy; projected type well production profiles (including the liquids component thereof) and associated net present value, internal rate of return and payout estimates (and the initial production rate, sales volumes, capital and operating cost, liquids yield, commodity price and other assumptions used to generate such profiles and estimates); and 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: future natural gas and liquids prices; royalty rates, taxes and capital, operating, general & administrative and other costs; foreign currency exchange rates and interest rates; general economic, market and business conditions; the ability of Paramount to obtain the required capital to finance its exploration, development and other operations and meets its commitments and financial obligations; 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; the ability of Paramount to secure adequate product processing, transportation, de-ethanization, fractionation and storage capacity on acceptable terms; the ability of Paramount to market its natural gas and liquids successfully to current and new customers; 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; the timely receipt of required governmental and regulatory approvals; and anticipated timelines and budgets being met in respect of drilling programs and other operations. Although Paramount believes that the expectations reflected in such forward-looking information are reasonable, undue reliance should not be placed on them 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 forwardlooking information. These risks and uncertainties include and/or relate (but are not limited) to: fluctuations in natural gas and liquids prices; changes in foreign currency exchange rates and interest rates; the uncertainty of estimates and projections relating to future revenue, future production, reserve additions, liquids yields (including condensate to natural gas ratios), resources recoveries, royalty rates, taxes and costs and expenses; the ability to secure adequate product processing, transportation, de-ethanization, fractionation and storage capacity on acceptable terms; operational risks in exploring for, developing and producing natural gas and liquids; the ability to obtain equipment, services, supplies and personnel in a timely manner and at an acceptable cost; potential disruptions or unexpected technical or other difficulties in designing, developing, expanding or operating new, expanded or existing facilities (including third-party facilities); processing, pipeline, de-ethanization, and fractionation infrastructure outages, disruptions and constraints; risks and uncertainties involving the geology of oil and gas deposits; the uncertainty of reserves estimates; general business, economic and market conditions; 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); changes in, or in the interpretation of, laws, regulations or policies (including environmental laws); the ability to obtain required governmental or regulatory approvals in a timely manner and to obtain and maintain leases and licenses; the anticipated benefits from the acquisition of Apache and merger with Trilogy not being realized; the effects of weather and other factors, including wildlife and environmental restrictions which affect field operations and access; 30

31 Advisories (con't) the timing and costs of future abandonment and reclamation obligations and potential liabilities for environmental damage and contamination; uncertainties regarding aboriginal claims and in maintaining relationships with local populations and other stakeholders; the outcome of existing and potential lawsuits, regulatory actions, audits and assessments; and other risks and uncertainties described elsewhere in this presentation and in Paramount s filings with Canadian securities authorities, including its Annual Information Form. The foregoing list of risks is not exhaustive. Additional information concerning these and other factors which could impact Paramount are included in Paramount s Annual Information Form. 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. Oil and Gas Measures and Definitions Abbreviations 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 All natural gas equivalency volumes have been derived using the ratio of six thousand cubic feet of natural gas to one barrel of oil. 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. During the quarter ended March 31, 2018 the value ratio between crude oil and natural gas was approximately 40:1. 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. Reserves and Other Information The Company s reserves were evaluated by McDaniel & Associates Consultants Ltd. (ʺMcDanielʺ) as of December 31, 2017 (the ʺMcDaniel Reserve Reportʺ). P+P Undeveloped Locations referred to in this document are the gross number of undrilled well locations included in the McDaniel Reserve Report. P+P and High Grade Locations referred to in this document are the P+P Undeveloped Locations plus internally identified high grade locations which have not been assigned reserves by McDaniel. Internal high grade is based on internal economic thresholds and recovery schemes. Internal remaining is based on reduced economic thresholds and more aggressive recovery schemes. Other properties include Montney assets at Birch, Presley, Fir and Ante Creek, and Duvernay assets at Kaybob North, Kaybob Bigstone, Kaybob Pine Creek, and Willesden Green. Estimated future net revenue is not necessarily representative of the fair market value of our properties and reserve volumes and there is no guarantee that the volumes will be recovered. Type well information is derived from internally generated type well models. The term IRR means the internal rate of return. IRRs are subject to a number of assumptions and risks, some of which are described herein and, accordingly, actual IRRs achieved may be materially different than that projected. The term "IP 30 means the initial 30 days of production. 30 day peak rate is the highest daily average production rate over a 30-day consecutive period for an individual well, measured at the wellhead. Natural gas sales volumes are approximately 10 percent lower and stabilized condensate sales volumes are approximately 15 percent lower due to shrinkage. Excludes days when the well did not produce. 30 day peak rates are measured over a short period of time and, therefore, are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from a well. 31

32 Advisories (con't) Paramount has provided information with respect to certain of its plays and emerging opportunities which is "analogous information" as defined in NI This analogous information includes Paramount's internally generated production type curves for certain of its wells and internal estimates of total sales volumes. This analogous information is derived from Paramount's internal sources as well as from a variety of publicly available information sources which are predominantly independent in nature (however, it is not clear in all cases whether analogous information derived from public sources was prepared by a qualified reserves evaluator or in accordance with the Canadian Oil and Gas Evaluation Handbook). These type curves and estimates are subject to the specific assumptions identified by Paramount with respect thereto, and the other assumptions contained in these advisories. No reserves, or resources other than reserves, are assigned to these type curve estimates and, accordingly, such estimates may not be representative of the actual production rates or resources associated with Paramount's wells and properties. 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. Analogous information is presented on a basin, sub-basin or area basis utilizing data derived from Paramount s internal sources as well as from a variety of publicly available sources which are predominantly independent in nature. Internal estimates are subject to the specific assumptions identified by Paramount in respect of such estimates plus other assumptions contained herein, and are not necessarily representative of the actual resources associated with Paramount s properties. The Liard Basin estimates set forth herein are as publicly disclosed by a large U.S. public E&P company. The resource evaluation disclosed by such E&P company was not noted as having been prepared independently or by a qualified reserves evaluator or auditor (as such terms are defined in NI ) or in accordance with the Canadian Oil and Gas Evaluation Handbook. This information is relevant to Paramount s landholdings in the Liard Basin as the information is in respect of landholdings in the Liard Basin that are close to Paramount s lands and are, accordingly, likely to have similar geology. Test Results The test rates disclosed in this document represent the average rate of production at the wellhead during post clean-up production testing at the largest choke setting. Pressure transient analyses and well-test interpretations have not been carried out for any of these wells and, as such, all data should be considered preliminary until such analyses or interpretations have been done. Test results are not necessarily indicative of long-term performance or of ultimate recovery. Non-GAAP Measures In this presentation "Net Debt" and "Cash Flow", collectively the "Non-GAAP measures", are used and do not have any standardized meaning as prescribed by GAAP. Net Debt is a measure of the Company s overall debt position after adjusting for certain working capital and other 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 calculation of Net Debt. Cash Flow means Adjusted Funds Flow and 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 calculation of Adjusted Funds Flow. 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. Non-GAAP Measures are unlikely to be comparable to similar measures presented by other issuers. 32

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