Corporate Presentation

Transcription

1 Corporate Presentation January 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. 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: ~$1.0 Bln (130.9 MM Insider ownership: ~46% Net Debt: $797 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) Nine Months Ended September 30, 2018 Results Production Capex Opex 86,429 Boe/d (~36% Liquids) $453 MM $11.77 / Boe 2018 Guidance 2018E Production 2018E Capex 2018E Opex 85,000-86,000 Boe/d (~37% Liquids) ~$600 MM <$12.00 / Boe 1) At September 30, 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 May 2017 closed the sale of Valhalla assets for ~$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 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 Executed first high-intensity Lower Montney completion at Karr with encouraging preliminary results; Lower Montney locations on Karr lands are being quantified (none currently recognized) 11 Montney wells drilled and completed at Wapiti on the 9-3 pad; wells are similar to Karr Montney wells - expected to have similar liquids-rich production profiles Well completions carried out at Kaybob at the 7-22 five-well South Duvernay pad and the fourwell Smoky Duvernay pad; both pads are currently producing The 5-29 Duvernay well at Willesden Green completed and brought on production Q Results have confirmed an over-pressure, high oil deliverability reservoir on Willesden Green Duvernay acreage 4

5 Grande Prairie Snapshot Operational Highlights 2018 Program Karr: drill two five-well pads; complete 1 pad Wapiti: drill 23 wells; complete 11 wells YTD Sept 30/18 Sales: 25,750 Boe/d (50% 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 Cretaceous upside across the Deep Basin trend Grande Prairie Inventory ~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. 5

6 Karr Montney Asset Detail (1) Operational Highlights Wells on the 1-2 pad are completed and on production Wells on the 4-24 pad are rig released and will be completed and brought on production in 2019 Avg peak 30-day wellhead rate of 1,971 Boe/d (~60% condensate) from 27 wells drilled in 2016/2017 and 1,809 Boe/d (~61% condensate) from five 2018 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 Executed first high-intensity Lower Montney completion at Karr with encouraging preliminary results The Facility expansion from 80 MMcf/d to 100 MMcf/d is complete; will be tied in when incremental capacity is required Debottlenecking projects at the facility and new trucking facilities are complete, increasing raw liquids handling capacity to ~15,000 Bbl/d The next growth phase of the 6-18 facility, which could be completed in 2020, includes an additional 50 MMcf/d of raw gas processing capacity and an additional 15,000 Bbl/d of hydrocarbon liquids processing capability; increasing raw capacity at 6-18 to 150 MMcf/d gas with 30,000 Bbl/d of hydrocarbon liquids handling 1) Refer to the heading Reserves and Other Information in the Advisories Appendix. 6

7 Wapiti Montney Asset Detail (1) Operational Highlights 9-3 pad wells drilled and completed: the completions set several new records due to advances in well design and program execution Additional 12 wells commenced drilling on the 5-3 pad Third party gas plant and infrastructure under construction with scheduled mid 2019 in-service 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 150 MMcf/d gas plant and infrastructure; expandable to 300 MMcf/d 1) Refer to the heading Reserves and Other Information in the Advisories Appendix. 7

8 Kaybob Snapshot (1) (1) Refer to the heading Reserves and Other Information in the Advisories Appendix. Operational Highlights 11 of 13 planned Montney oil wells have been drilled and put on production 9 of 14 planned Duvernay wells are completed and on production; drilling operations commenced on the 2-28 pad Smoky plant expanded to 12 MMcf/d YTD Sept 30, 2018 Sales: 39,592 Boe/d (31% 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 8

9 Kaybob Duvernay Asset Details (1) Operational Highlights Kaybob Smoky pad: 4 wells drilled, completed and flowing through permanent facilities Kaybob South 7-22 pad: 5 wells drilled, completed and on production with an average 30-day peak CGR of 199 Bbl/MMcf Special projects include fibre optics and micro-seismic Kaybob South 2-28 pad: 5 wells commenced drilling in September 2018 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. 9

10 Kaybob Montney Oil Development (1) Operational Highlights 2018 activity: 11 of 13 Montney horizontal wells are completed and on production Two remaining wells were drilled in Q 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. 10

11 Central Alberta & Other Snapshot (1) Operational Highlights 2018 Program: W5 hz Duvernay well at Willesden Green on production: peak 30-day rate of 944 Boe/d (total producing days 95) Three Glauconite wells at Leafland have been completed and are on production YTD Sept 30, 2018 Sales: 21,087 Boe/d (30% 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. 11

12 Willesden Green (1) Operational Highlights Horizontal well at 5-29 completed and on production Asset Potential Duvernay Shale Play 59,686 acres of land (100% WI) Drilled and completed 5 Hz Duvernay wells to date 00/05-29 Cum Production to January 2, MMcf Gas 82,456 Bbl Oil 1) Refer to the heading Reserves and Other Information in the Advisories Appendix. 12

13 2018 Capital Program 2018 Capex ~$600 million (excluding acquisitions & divestitures) Plan included drilling ~68 development wells and completing ~47 of those wells 47 well completions represent ~11% of PRL s P+P undeveloped locations (1) Drilling services provided by Paramount's wholly-owned Fox Drilling, which owns seven triple-sized rigs; the Company 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 in Q at C$71.61/Bbl WTI; 14,000 Bbl/d of liquids hedged for 2019 at C$77.05/Bbl WTI (2) Paramount has arrangements in place to transport and sell approximately 60,000 GJ/d of natural gas at the Dawn natural gas hub in Ontario ($US NYMEX ref prices) and 21,000 GJ/d of natural gas in California ($US Malin ref prices). As of November 2018, Paramount further diversified its natural gas sales arrangements, with an additional 40,000 GJ/d priced in the US Midwest 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 13

14 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 14

15 Strategic and Long-Term Investments 1) Please refer to the heading Reserves and Other Information in the Advisories Appendix. 2) Publicly disclosed by competitor. 15

16 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: $1.5 Billion long-term bank credit facility (incl. accordion) with $695 MM drawn at September 30, 2018 Net debt: $797 MM (2) 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) As of December 31, Refer to the heading Reserves and Other Information in the Advisories Appendix 2) Refer to the heading Non-GAAP Measures in the Advisories Appendix 16

17 Appendix: Additional Information

18 Performance 1) Represents midpoint of 2018 production guidance 2) As evaluated by McDaniel & Associates Consultants Ltd. as of December 31,

19 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. 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) forecast capital expenditures (including the plays and activities in respect of which this capital is expected to be spent); (iii) operating costs per BOE; (iv) budgeted abandonment and reclamation costs; (v) reserves estimates; (vi) 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); (vii) estimated numbers of drilling locations (including high grade locations); (viii) ongoing enhancements in Paramount s well completion techniques; (ix) the projected ability of the Company s existing midstream infrastructure and commitments to facilitate its Montney and Duvernay development plans through 2021; and (x) 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, 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 meets 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 timely receipt of required governmental and regulatory approvals; and (xi) 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 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), resources recoveries, 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 anticipated benefits from the acquisition of Apache and merger with Trilogy not being realized; (xvi) the effects of weather and other factors, including wildlife and environmental restrictions which affect field operations and access; (xvii) the timing and costs of future abandonment and reclamation obligations and potential liabilities for environmental damage and contamination; (xviii) uncertainties regarding aboriginal claims and in maintaining relationships with local populations and other stakeholders; (xix) the outcome of existing and potential lawsuits, regulatory actions, audits and assessments; and (xx) other risks and uncertainties described elsewhere in this presentation and in Paramount s filings with Canadian securities authorities, including its Annual Information Form. 21

22 Advisories (con't) The foregoing list of risks is not exhaustive. 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 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 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. For the nine months ended September 30, 2018, the value ratio between crude oil and natural gas was approximately 55:1. 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). See the Company s Annual Information Form for additional information respecting the McDaniel Reserve Report and the Company s operations and reserves. P+P Undeveloped Locations referred to in this document are the gross number of proved plus probable 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. 22

23 Advisories (con't) Type well information is based on internal management estimates. Type well information is subject to a number of assumptions and actual results achieved may be materially different than that projected. Peak 30-day 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. Peak 30-day 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. Paramount has provided information with respect to the Liard Basin which is "analogous information" as defined in NI 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. Such estimates may not be representative of the actual resources associated with Paramount's properties. 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. 23

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