CORPORATE PRESENTATION

Transcription

1 TSX: YGR YGR 1-26 PAD CORPORATE PRESENTATION NOVEMBER 2018

2 CORPORATE SNAPSHOT WELL CAPITALIZED, STRONG INSIDER OWNERSHIP & A DEFINED RESOURCE BASE CAPITALIZATION SUMMARY CARDIUM LAND POSITION Additional Information Basic Shares mm % Insider Ownership Options mm 8.3 $3.77 Weighted Average Ex. Price Fully Diluted mm % Total Insider Ownership Market Capitalization $mm $302.8 $3.55 Share Price at 06-Nov-18 Plus Q3 Net Debt $mm $135.7 $175.0 Total Credit Facility Enterprise Value $mm $ BUDGET (REVISED AUGUST 2018) Average 2018E Guidance boe/d 9,500 Guidance Range boe/d 9,000-10,000 Expected Cash Flow $mm $85 CFPS - basic $/share $ Capital $mm $140 # of wells planned 30 YE Exit Debt $mm 140 YE 2017 RESERVES & LOCATIONS mmboe BT NPV10 RR Proved Dev. (PDP) 12.0 $ x YE 2017 Reserves booked using Total Proved 55.9 $ x older well designs Proved + Probable 87.9 $1, x $ P NAV per FD Share Booked Locations Total Locations Additonal Information (Gross) (Net) (Gross) (Net) August % Booked Yangarra Bioturbated Wells CONCENTRATED HALO CARDIUM PLAYER Fracking in bioturbated zone driving higher recoveries across entire Cardium package Applying industry leading practices in multi-stage frac d (MSF) horizontal wells >50 wells drilled since August 2016 fully delineating the entire land base NOVEMBER 2018 PG 2

3 INVESTMENT THESIS DISCIPLINED GROWTH THROUGHOUT ENTIRE DEVELOPMENT CYCLE OPERATIONALLY FOCUSED LOW-COST PRODUCER Focus on halo, bioturbated Cardium provides Yangarra with a proprietary knowledge base AND operational synergies Continuous improvement approach to drilling & completions Yangarra s investment in infrastructure drives economic success Low op costs a result of corporate structure Organic growth company owned infrastructure drives low operating costs Low G&A costs Strongly aligned management comp structure incentivized to drive share price returns STRONG ORGANIC GROWTH Excellent per share growth in 2018E: >60% on production >60% on cash flow Expect continued growth into foreseeable future at current commodity prices Competitive first-mover advantage allows Yangarra to ALSO grow economic inventory DISCIPLINED CAPITAL STEWARDS Focused on full-cycle rates of return Prudent balance sheet management provides considerable flexibility Belief in a budget program that builds a sustainable growth model YANGARRA IS A CORE HOLDING FOR INVESTORS LOOKING FOR AN INTERNALLY FINANCED GROWTH STORY AT A COMPELLING VALUATION NOVEMBER 2018 PG 3

4 Production (boe/d) STRATEGIC OUTLOOK SUSTAINABLE GROWTH & INTERNALLY FUNDED REMAIN CONCENTRATED Geographically & geologically concentrated in the prolific Cardium sands Concentration drives multiple synergies from geology, to drilling, to production (leading producer of bioturbated zone) 35,000 30,000 25,000 20,000 PRODUCTION POTENTIAL WITH 2 RIGS (YEAR-ROUND) (1) Assumes 30 locations/year (45-one mile) & ~500 net locations remaining at Year 5 15,000 SHAREHOLDER VALUE THROUGH FULL CYCLE ECONOMICS Achieve consistent top quartile program drilling results Be the lowest cost producer to maximize netbacks Op costs of $7-8 per boe (all-in, including transportation) G&A costs of <$1.00 per boe ORGANIC GROWTH Focus on growing per share metrics Funded within cash flow Disciplined use of debt capital to finance program ~1.0x Debt/Annualized YE CF 10,000 5,000 0 Year 1 Year 2 Year 3 Year 4 Year 5 TRANSITION FROM DELINEATION TO MANUFACTURING Yangarra believes running a 2-rig program yearround (accounting for break-up) will optimize operations Using static/current D&C costs and current commodity prices, Yangarra can internally finance a 2-rig program for the foreseeable future and continue to grow inventory NOVEMBER 2018 PG 4

5 LEADERSHIP EXPERIENCED & GEARED FOR DEVELOPMENT MANAGEMENT TEAM BOARD OF DIRECTORS Jim Evaskevich President & CEO years of extensive executive experience - Strong field & drilling operational background Gordon Bowerman Chairman - President of Cove Resources Ltd years of oil & gas experience Lorne Simpson, B.Sc., C.E.T. VP Operations years of experience in oil & gas - Drilling operations Neil Mackenzie - Director at various public companies - Partner at Blackstone Fluids Randall Faminow VP Land years of experience in oil & gas - Negotiations in acquisitions and divestments Robert Weir - President of Weir Resource Management Ltd. James Glessing, CA Chief Financial Officer years of oil & gas accounting experience - Ex-controller & CFO at various energy firms - Articled at Deloitte Ted Morton - Former Albertan & Canadian politician; Held Energy, Finance, Enterprise, and Sustainable Resources Minister positions Gurdeep Gill, CFA VP Business Development years of experience in capital markets - Head of investment banking at AltaCorp Jim Evaskevich - See bio in management team. INSIDER OWNERSHIP BOTH AT THE MANAGEMENT LEVEL AND THE BOARD LEVEL PROVIDES STRONG ALIGNMENT WITH SHAREHOLDERS NOVEMBER 2018 PG 5

6 HALO CARDIUM INVENTORY ACCUMULATION FULL CYCLE FOCUS NOT JUST A SAYING, KEY DRIVER IN ALL DECISION MAKING TBD Competitive advantage of operational and geological knowledge, combined with owned infrastructure allowing Yangarra to compete in acquiring additional lands Go-forward focus on operations (2 rigs); established infrastructure and pad drilling should continue to drive above average returns INFRASTRUCTURE Yangarra s 2018 infrastructure spending to drive full-field development % Half Cycle 83% Full Cycle Success of bioturbated drilling resulted in a first-mover advantage as Yangarra led peers in drilling & acquiring lands Continuous improvements in technology (per each 10-well program) drove further operational & economic success BIOTURBATED ZONE Initial bioturbated well changed Yangarra s approach to the Cardium % Half Cycle 29% Full Cycle With a focus on the Cardium, Yangarra started deploying sliding sleeves & cemented liners to improve MSF approach to longer well lengths During commodity downturn, focused on acquiring land at reasonable prices TRANSITION TO FULL CYCLE Stopped pursuing multiple play types; focused on Cardium % Half Cycle 26% Full Cycle Pursued multiple plays using MSF technology (Glauconite, Rock Creek, Second White Specks, Viking) Very low Cardium inventory NOVEMBER 2018 PG 6

7 CARDIUM EVOLUTION CONVENTIONAL CARDIUM TO TIGHTER HALO CARDIUM CONVENTIONAL CARDIUM HALO CARDIUM 1950 S TO 2009 Prolific Cardium sands exploited by vertical wells INITIAL TECHNOLOGICAL SHIFT Cardium potential expands dramatically with the introduction of new technology initiatives to the Halo Cardium Early approaches include: Horizontal wells Multi-stage fracs Gel-oil fracs Slick water fracs Capital intensive; highly dependent on highcommodity prices or low drill/frac costs 2009 TO 2014/15 Renaissance in Cardium until 2014 oil crash; capex dropped dramatically Technology continues to progress in other plays across North America End of Cardium story? NOVEMBER 2018 PG 7

8 CARDIUM REVOLUTION CONGLOMERATE TO BIOTURBATED ORIGINAL LOG & BIOTURBATED CORE EXAMPLE NEW FRAC PLANE Willesden Green T41-R6W/5 Net Pay Upper Sand Core analysis Porosity 10-15% TECHNOLOGY PROGRESSION Shift by Yangarra to: Cemented liners Sliding sleeves Extended reach wells Fracking into bioturbated zone allows frac to vertically propagate in both directions Old Well Path New Well Path Deeper well path allows YGR to access significantly more OBOEIP Upper m Bioturb m Lower m Bioturbated Log Porosity 3% Gas-charge drives higher oil and NGLs recoveries (see type curve) IT S ALL ABOUT OOIP/OBOEIP YGR BIOTURBATED VIEW Actual core analysis (by YGR & Weatherford) shows porosity increases to 4-6% Materially increasing OOIP/OBOEIP UPPER CARDIUM OOIP TARGET ~2-5 mmbbl OOIP ~6-20 mmboe OBOEIP PLUS BIOTURBATED ~4.5-6 mmbbl OOIP ~12-18 mmboe OBOEIP TOTAL OOIP ~ mmbbl OOIP ~18-38 mmboe OBOEIP NOVEMBER 2018 PG 8

9 OPERATIONS OVERVIEW ENTIRETY OF YANGARRA S FOCUS ON OPERATIONS IN THE CARDIUM Since 2016, Halo Cardium has been the focus Land acquisition strategy has been driven by OOIP at reasonable prices A major portion of the drill program has been to earn farm-ins and push the boundaries of the Cardium Improvements in technology & step-out wells have significantly increased opportunity for additional acquisitions Evolution of Yangarra s initial ten-well program to most recent program in 2018 Initial wells had 30 stages and 450 tons (per mile) Recent wells with a range of 60 to 96 stages and 1,200 to 1,900 tons (per mile) Yangarra Bioturbated Wells Yangarra continues to experiment with well lengths, frac stages, tons and spacing with a goal of full-field development with pad drilling Savings on initial pad for drill & completion costs should continue to drive future IRR performance NOVEMBER 2018 PG 9

10 Cumulative Production (mboe) Production Per Day (boe/d) ECONOMICS EXCELLENT IRRS WILL CONTINUE TO DRIVE FUTURE PER SHARE GROWTH UNRISKED WEIGHTED-AVERAGE TYPE CURVE PRODUCTION PROFILE UNRISKED WEIGHTED-AVERAGE TYPE CURVE ASSUMPTIONS Total (boe/d) Year 1 BOE Decline: 39% Oil (bbl/d) Total NGLs (bbls/d) Months CUMULATIVE PRODUCTION Cumulative (mboe) Cumulative Oil (mbbl) Cumulative NGLs Avg. Type DCET $mm $3.75 IP30 - Oil bbl/d 313 IP30 - BOE boe/d 493 IP90 - Oil bbl/d 261 IP90 - BOE boe/d 480 IP365 - BOE boe/d 442 Capital Eff. (1st year) $/boe/d $8,484 EUR mboe 522 F&D (Half Cycle) $/boe $7.61 EURs will range across land base depending upon OBOEIP & gas-rates Average NGLs Yield 55 bbl/mmcf (life of well) Average Weighted Type Curve Price Sensitivity: WTI (USD/bbl) $50.00 $60.00 $70.00 $80.00 IRR % 109% 198% 308% 458% NPV10% $mm $5.4 $7.8 $10.0 $12.0 Payback years Recycle Ratio x 3.7x 4.5x 5.3x 6.0x *Above is a weighted average type curve encompassing 1-mile & 2-mile wells. The above EUR will not match the "Section Analysis" on the Inventory slide Yangarra reviews each individual area & specific targets and assigns type curves based on detailed geological reviews and rigorous reservoir parameters (i.e. differing net pays per zone, porosities and GORs) Months For competitive reasons, Yangarra has provided an average type curve that encompasses our results across our inventory, which is in turn weighted using our inventory from each area NOVEMBER 2018 PG 10

11 CARDIUM INVENTORY DISCIPLINED APPROACH DRIVES LAND ACQUISITION STRATEGY LAND & INVENTORY SUMMARY SAMPLE ONE-SECTION EXPLOITATION STRATEGY INVENTORY STRATEGY Gross Net WI Total Sections Total Acres 87,200 68,224 78% Locations Locations are an internal management estimate on a 1-mile basis (includes 2-mile locations converted to 1-mile equivalents for ease of use) ONE WELL OBOEIP/Section ~18-38 mmboe (~ mmbl OOIP) Well Recovery Factor ~15-16% Section Recovery Factor ~1.5% 4 WELLS / SECTION OOIP/Section ~18-38 mmboe (~ mmbl OOIP) Well Recovery Factor ~15-16% Section Recovery Factor ~6% 10 WELLS / SECTION OOIP/Section ~18-38 mmboe (~ mmbl OOIP) Well Recovery Factor ~15-16% Section Recovery Factor ~15-16% Per section drilling will vary with GOR levels. Low GOR areas will have higher drilling density; high GOR areas will have lower drilling density Yangarra divides Cardium operations into six areas with each area having an individual type curve Where the type curve does not meet internal economic thresholds, Yangarra does not include those lands in the inventory count GEOLOGICAL MAPPING, RESERVOIR PARAMETERS & ECONOMIC TYPE CURVE KEY TO INVENTORY COUNT Recoveries from tight, unconventional horizontal wells materially different from conventional Cardium Yangarra and its third-party reserve engineers forecast a horizontal well will drain up to ~64 acres due to tight reservoir parameters Well drilling & frac design are optimized to minimize horizontal fracturing & maximize vertical fracturing Empirical evidence from 42+ wells drilled highlights minimal communication between horizontal wells at 150m spacing (even at 100m) and offsetting verticals (where the case may be) Well spacing for inventory ranges from six to 10 wells per undrilled section Yangarra s inventory count evolves based on well performance, technological progress and the acquisition of additional targeted lands NOVEMBER 2018 PG 11

12 PRODUCTION LOGISTICS OWNING INFRASTRUCTURE AND MINIMIZING THIRD-PARTY PROCESSING/FLUID HANDLING OPTIMIZES OUR COSTS YANGARRA INFRASTRUCTURE Operating interest above 90% Low operating costs and high netbacks achieved through a variety of production strategies: Processing gas through owned facilities Truck emulsion to central batteries Creating right blend maximizes revenue per bbl Yangarra Facilities Requirement for a traditional contiguous land base to optimize operating costs and drilling operations eliminated with trucking & pads Trucking emulsion allows Yangarra to chase the best opportunities to acquire lands (scarcely drilled, high OBOEIP/OOIP, bioturbated presence) Flexibility to deliver liquids minimizes risk of apportionments (no take or pay obligations on oil or gas) NOVEMBER 2018 PG 12

13 LQA Produciton (boe/d) 2018E Netback EV / 2019E DACF EV / 2019E Production 2018E / 2017 Production Growth 2019E / 2018E Production Growth 2019E Sustainability COMPARATIVE METRICS & VALUATION YANGARRA CONTINUES TO BE AN OUTLIER IN SUSTAINABLE GROWTH ONGOING GROWTH EXPECTATIONS (CONSENSUS) INTERNALLY FINANCED (CONSENSUS) ROBUST BALANCE SHEET (CONSENSUS) 100% POU 50% YGR 140% POU 90% 80% 70% YGR 60% 50% 40% NVA 30% WCP VET KEL TVE DEE TOG SGY 20% VII IPO GXE ERF 10% BNE JOY OBE PPR 0% 0% 10% 20% 30% 40% 50% 45% PPR NVA 40% 35% GXE 30% SGY KEL 25% VET 20% IPO POU TOG 15% OBE DEE TVE ERF VII 10% WCP BNE 5% JOY 0% 60% 80% 100% 120% 140% 130% 120% NVA DEE 110% PPR 100% KEL IPO VII OBE 90% YGR JOY 80% ERF SGY TVE WCP GXE TOG VET BNE 70% 60% 0.0x 0.5x 1.0x 1.5x 2.0x 2.5x 3.0x 2019E / 2018E Production Growth 2019E Sustainability 2018E Net Debt / 2019E Cash Flow LOW OP COST PRODUCER HIGH NETBACKS 2019 CONSENSUS VALUATION 100,000 ERF VET $35.00 TOG 6.0x $60,000 90,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10,000 YGR KEL DEE NVA POU WCP TOG TVE SGY OBE BNE JOY PPR GXE IPO $30.00 $25.00 $20.00 $15.00 $10.00 $5.00 DEE KEL JOY VET ERF YGR VII TVE OBE BNE IPO PPR WCP SGY GXE 5.0x 4.0x 3.0x 2.0x 1.0x YGR $50,000 $40,000 $30,000 $20,000 $10,000 0 $3.00 $6.00 $9.00 $12.00 $15.00 $18.00 LQA Operating Cost ($/boe) Source: AltaCorp Capital Inc. $ % 50% 60% 70% 80% 90% 100% 2018E %Liquids 0.0x EV / 2019E DACF EV / 2019E Production $0 YANGARRA CONTINUES TO PROVIDE INDUSTRY LEADING GROWTH, COMBINED WITH A STRONG BALANCE SHEET & HIGH NETBACKS, AT A VERY COMPELLING VALUATION NOVEMBER 2018 PG 13

14 DUVERNAY OPTION SIZE OF PRIZE REMAINS IN HAND WITH RELATIVELY LOW LEVEL OF CAPITAL COMMITMENT Yangarra Duvernay Rights YANGARRA S DUVERNAY POSITION ON-TREND WITH THE ABOVE WELLS DRILLED IN THE AREA; DE-RISKING BY INDUSTRY WILL DRIVE OPTIONALITY FOR YANGARRA NOVEMBER 2018 PG 14

15 CONCLUSION TRANSLATING IRR INTO EXCEPTIONAL GROWTH COMPETITIVE ADVANTAGE IN HALO CARDIUM KEY TO YANGARRA INVESTORS Yangarra is a prolific, organic growth producer with an excellent, focused runway of inventory During the past two years, Yangarra unlocked the previously unexploitable bioturbated zone, fully unlocking the total Cardium pay package, maximizing the recoverable resource Capitalized on first-mover advantage to acquire acreage in key Cardium lands in target areas at reasonable acquisition prices Utilized geologic and operational know-how to pin point strategic land opportunities with an eye on full-cycle economics 15+ years Inventory Accumulated 20+ sections in 2018 Avg IP 365: >400 boe/d Executed on a successful and diverse 40+ well program that de-risked Yangarra s resource base Successfully ran a year-round two-rig program for the past 12 months >50% CFPS Growth (2018E/2017) Laid the groundwork for continued, peer leading per share growth for the foreseeable future by building out infrastructure to handle higher volumes EV/DACF (2019 Consensus): <3.0X EV/BOED (2019 Consensus): ~$30,000 YANGARRA S COMPELLING VALUATION, STRONG BALANCE SHEET AND CONTINUED GROWTH PROFILE MAKES YANGARRA A KEY CORE HOLDING FOR INVESTORS LOOKING TO ADD EXPOSURE TO CANADIAN ENERGY NOVEMBER 2018 PG 15

16 APPENDIX RISK MANAGEMENT, ANALYST COVERAGE, PRESENTATION FOOTNOTES & FORWARD LOOKING STATEMENTS NOVEMBER 2018 PG 16

17 ANALYST COVERAGE STREET COVERAGE CONTINUES TO GAIN MOMENTUM Acumen Capital Finance Partners Ltd. Trevor Reynolds (403) AltaCorp Capital Inc. Thomas Matthews, P.Eng, CFA (403) Canaccord Genuity Sam Roach, CFA (403) CIBC World Markets Scott Reid, CFA (403) Cormark Securities Inc. Amir Arif, CFA (403) Industrial Alliance Securities Inc. Michael Charlton (403) Laurentian Bank Securities Todd Kepler, CFA (403) Paradigm Capital Inc. Ken Lin, CFA (403) Peters & Co Dan Grager (403) Raymond James Ltd. Jeremy McCrea, CFA (403) Recently Added Coverage: TD Securities Ltd. Sean Keaney (403) National Bank Financial John Hunt (403) NOVEMBER 2018 PG 17

18 PRESENTATION FOOTNOTES SEPTEMBER 2018 Slide 2: 30 locations (45 one-mile equivalents); WTI US$55.00 Ed. Par C$63.75, AECO C$2.00/GJ; Reserves effective as at December 31, 2017 based on the reserve report prepared by Deloitte LLP, independent petroleum engineers (the Reserves Report ). NAV = NPV10 Reserve Value less Net Debt and excludes undeveloped land value Slide 4: Assumes $120MM capital program each year and 2-rigs year-round with break-up resulting in 30 locations a year (based off of type curve provided in presentation). Slide 6: Half cycle IRR is based on actual drilling and completion costs, production to date and P+P reserves; Full cycle IRR allocates all other capital costs to the wells (i.e. land, G&G, infrastructure) Slide 10: Flat commodity price assumptions: Ed. Par differential US$5.00, F/X , AECO C$1.75/GJ; Operating cost of $7.00/boe including transportation; Type curves are based off of a inventory weighted average type curve for each area using both 1.0 mile and 2.0 mile data. Slide 11: Inventory is an internal management estimate. Slide 13: Based off of Consensus data as at September 2018 Additional Information/Terminology: Gas converted at 6 mcf : 1 barrel of equivalent basis (BOE) OOIP: original oil in place; OBOEIP: original barrels of equivalent in place NOVEMBER 2018 PG 18

19 FORWARD LOOKING STATEMENTS This presentation contains a summary of management's assessment of results and should be read in conjunction with the Consolidated Financial Statements and related Management's Discussion and Analysis for the quarter ended June 30, 2018, as filed on the SEDAR profile of Yangarra Resources Ltd. (the "Company"). This presentation contains certain forward-looking statements, which include assumptions with respect to (i) drilling success; (ii) commodity prices; (iii) production; (iv) reserves; (v) future capital expenditures; (vi) future operating costs; (vii) cash flow; and (viii) potential markets for the Company's production. The reader is cautioned that assumptions used in the preparation of such information may prove to be incorrect. Certain information regarding the Company set forth in this presentation, including statements regarding management's assessment of the Company's future plans and operations, the planning and development of certain prospects, the 2018 Capital Program and the Company's proposed exploration and development activities and the timing thereof, including the amount and allocation of capital expenditures, the number and types of wells to be drilled and brought on production and the timing thereof, estimates of total and net capital expenditures, and the focus of, the objectives of and the anticipated results from the 2018 Capital Program, production estimates, reserve estimates, productive capacity and economics of new wells, undeveloped land holdings and values, capital expenditures and the timing and allocation thereof (including the number, location and costs of planned wells), the total future capital required to bring undeveloped proved and probable reserves onto production, and expected production growth, may constitute forward-looking statements under applicable securities laws and necessarily involve substantial known and unknown risks and uncertainties. With respect to the Company's 2018 production guidance, the key assumptions are that: the 2018 Capital Program will be carried out as currently contemplated; no unexpected outages occur in the infrastructure that the Company relies on to produce its wells and that any transportation service curtailments or unplanned outages that occur will be short in duration or otherwise insignificant; existing wells continue to meet production expectations; and future wells scheduled to come on production meet timing, production and capital expenditure expectations. These forward-looking statements are subject to numerous risks and uncertainties, certain of which are beyond the Company's control, including without limitation, risks associated with oil and gas exploration, development, exploitation, production, marketing and transportation, loss of markets, failure of foreign markets to become accessible, the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, environmental risks, competition, the lack of availability of qualified personnel or management, inability to obtain drilling rigs or other services, capital expenditure costs, including drilling, completion and facility costs, unexpected decline rates in wells, wells not performing as expected, stock market volatility, delays resulting from or inability to obtain required regulatory approvals and ability to access sufficient capital from internal and external sources, the impact of general economic conditions in Canada, the United States and overseas, industry conditions, changes in laws and regulations (including the adoption of new environmental laws and regulations) and changes in how they are interpreted and enforced, increased competition, fluctuations in foreign exchange or interest rates and market valuations of companies with respect to announced transactions and the final valuations thereof. Readers are cautioned that the foregoing list of factors is not exhaustive. The Company's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits the Company will derive therefrom. All subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. Additional information on these and other factors that could affect the Company's operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website ( or the Company's website ( including the Company's MD&A for the quarter June 30, NOVEMBER 2018 PG 19

20 FORWARD LOOKING STATEMENTS (CONT.) The forward-looking statements contained in this presentation are made as of the date on the front page and the Company assumes no obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities laws. Certain information contained herein is based on, or derived from, information provided by independent third-party sources. The Company believes that such information is accurate and that the sources from which it has been obtained are reliable. The Company cannot guarantee the accuracy of such information, however, and has not independently verified the assumptions on which such information is based. The Company does not assume any responsibility for the accuracy or completeness of such information. This presentation also contains future-oriented financial information and financial outlook information (collectively, "FOFI") about prospective results of operations, cash flow, capital expenditures, net debt and components thereof, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth in the above paragraphs. FOFI contained in this presentation was made as of the date of this presentation and was provided for the purpose of providing information about management's current expectations and plans relating to the future, including with respect to the Company's ability to fund its expenditures. The Company disclaims any intention or obligation to update or revise any forward-looking statements or FOFI contained in this presentation, whether as a result of new information, future events or otherwise, unless required pursuant to applicable securities law. Readers are cautioned that the forward-looking statements and FOFI contained in this presentation should not be used for purposes other than for which it is disclosed herein. The forward-looking statements and FOFI contained in this presentation are expressly qualified by this cautionary statement. NOVEMBER 2018 PG 20

21 FORWARD LOOKING STATEMENTS NON-GAAP MEASURES & ANALOGOUS INFORMATION This presentation contains references to measures used in the oil and natural gas industry such as netback, net debt and cash flow. These measures do not have standardized meanings prescribed by International Financial Reporting Standards ( IFRS ) and therefore should not be considered in isolation. These reported amounts and their underlying calculations are not necessarily comparable or calculated in an identical manner to a similarly titled measure of other companies where similar terminology is used. Where these measures are used they should be given careful consideration by the reader. These measures have been described and presented in this presentation in order to provide shareholders and potential investors with additional information regarding the Company's liquidity and its ability to generate funds to finance its operations. Netback denotes petroleum and natural gas revenue and realized gains or losses on financial instruments less royalty expenses, operating expenses and transportation and marketing expenses calculated on a per boe basis. Cash flow should not be considered an alternative to, or more meaningful than, cash provided by operating, investing and financing activities or net earnings as determined in accordance with IFRS, as an indicator of the Company's performance or liquidity. Cash flow is used by the Company to evaluate operating results and the Company's ability to generate cash flow to fund capital expenditures and repay debt. Included in this presentation are estimates of the Company's 2018 cash flow which are based on various assumptions as to production levels, commodity prices and other assumptions, are provided for illustration only and are based on budgets and forecasts that have not been finalized and are subject to a variety of contingencies including prior years' results. To the extent such estimates constitute a financial outlook, they were approved by management of the Company and are included to provide readers with an understanding of the Company's anticipated cash flow based on the capital expenditures and other assumptions described and readers are cautioned that the information may not be appropriate for other purposes. The Company uses net debt as a measure to assess its financial position. Net debt includes current liabilities (including the Company's credit facility and excluding the current portion of decommissioning obligations) less current assets (excluding property, plant and equipment, held for sale and risk management contracts). Certain information provided in this news release may constitute "analogous information" under applicable securities legislation, such as reserve and resource estimates or the reserves and resources present on the Company's lands, and nearby lands, total production and production-rates from wells drilled by the Company or other industry participants located in geographical proximity to lands held by the Company. This information is derived from publicly available information sources (as at the date of this news release) that the Company believes are predominantly independent in nature. The Company believes this information is relevant as it helps to define the reservoir characteristics in which the Company may have an interest. The Company is unable to confirm that the analogous information was prepared by a qualified reserves evaluator or auditor or in accordance with the Canadian Oil and Gas Evaluation Handbook and therefore, the reader is cautioned that the data relied upon by the Company may be in error, may not be analogous to the Company's land holdings and/or may not be representative of actual results of wells anticipated to be drilled or completed by the Company in the future. NOVEMBER 2018 PG 21

22 FORWARD LOOKING STATEMENTS RESERVE DEFINITIONS Natural gas has been converted to a barrel of oil equivalent (Boe) using 6,000 cubic feet (6 Mcf) of natural gas equal to one barrel of oil (6:1), unless otherwise stated. The Boe conversion ratio of 6 Mcf to 1 Bbl is based on an energy equivalency conversion method and does not represent a value equivalency; therefore Boe's may be misleading if used in isolation. References to natural gas liquids ("NGLs") in this presentation include condensate, propane, butane and ethane and one barrel of NGLs is considered to be equivalent to one barrel of crude oil equivalent (Boe). One ("BCF") equals one billion cubic feet of natural gas. One ("Mmcf") equals one million cubic feet of natural gas. Reserve Definitions: "Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. "Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. "Developed" reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production. "Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty. "Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown. "Undeveloped" reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned. The Net Present Value (NPV) is based on Deloitte AJM Forecast Pricing and costs. The estimated NPV does not necessarily represent the fair market value of our reserves. There is no assurance that forecast prices and costs assumed in the Deloitte AJM evaluations will be attained, and variances could be material. This presentation contains references to measures used in the oil and natural gas industry such as netback. These measures do not have standardized meanings prescribed by GAAP and therefore should not be considered in isolation. These reported amounts and their underlying calculations are not necessarily comparable or calculated in an identical manner to a similarly titled measure of other companies where similar terminology is used. Where these measures are used they should be given careful consideration by the reader. These measures have been described and presented in this presentation in order to provide shareholders and potential investors with additional information regarding the Corporation's liquidity and its ability to generate funds to finance its operations. Netback denotes petroleum and natural gas revenue and realized gains or losses on financial instruments less royalty expenses, operating expenses and transportation and marketing expenses calculated on a per boe basis. NOVEMBER 2018 PG 22