C O R P O R A T E P R E S E N T A T I O N A P R I L 2 0 1 8 BOLD IDEAS FOR ENERGY 1
Financial Profile Financial Profile (TSX: PMT ) December 31, 2017 except as noted Common Shares o/s (1) 59.3 million Management ownership 49% Share price (1) $ 0.67 Market capitalization $ 40 million Net bank debt (2)(4) TOU share-based loan (3) Term Loan Senior unsecured notes TOU Shares (1.67 million) (3) Net debt (4) Enterprise value (4) $ 48 million $ 18 million $ 45 million $ 32 million ($ 38 million) $ 106 million $ 146 million (1) April 4, 2018 market price of $0.67/share (2) Net Revolving bank debt, net of working capital (4) at December 31, 2017 (3) Loans secured by 1.67 MM Tourmaline Oil Corp. (TSX: TOU ) shares; Market price at December 31, 2017 $22.75/share (4) See Non-GAAP measures advisory in this presentation 2
Operating Profile Deep Basin Edson Wilrich Multi-zone liquids-rich gas Tight oil & gas exploration Eastern Alberta Mannville heavy oil Conventional shallow gas Viking shallow shale gas Bitumen Asset Summary Production (1) Natural Gas (87%) Oil and NGL (13%) P+P Reserves (2) 13,100 boe/d 11,350 boe/d 1,750 bbl/d 66.6 MMboe LIQUIDS-RICH GAS East Edson Deep Basin Other HEAVY OIL Mannville SHALLOW GAS & OTHER Conventional Misc. Panny Tight Shallow Gas BITUMEN Panny, Liege, Other Reserve to Production Ratio (P+P) (RLI) (3) 13 Years Bitumen (DPIIP) (4) 1,292 MMbbl Tourmaline Oil Corp. Shares 1.67 million (5) $ 38 million (1) Production February 2018 (2) Year End 2017 N1 51-101 McDaniel Report on Reserves Data (3) Year-end Reserves divided by year one production estimate from McDaniel Report (4) DPIIP (Discovered Petroleum Initially In Place), evaluated by internal qualified reserves evaluator in accordance with COGE Handbook effective January 1, 2018 (5) Market price @ December 31, 2017 = $22.75/TOU share 3
Production (% of Total) Proved and Probable Reserves (% of Total) High Graded Asset Base 100% 90% 80% 70% 60% Building a foundation of resource-style plays Robust multi-zone inventory for profitable exploration and development High working interest, operatorship and infrastructure control 100% 90% 80% 70% 60% 50% 40% 30% 20% Higher value sales mix Liquids-rich gas Higher heat content gas Condensate & NGL sales Heavy oil 50% 40% 30% 20% 10% 10% 0% 2013 2014 2015 2016 2017 2018E 0% 2013 2014 2015 2016 2017 Production base focused on East Edson Deep Basin and Mannville 4
2018 Strategic Priorities Grow Value of Greater Edson Liquids-Rich Gas Grow Value of Eastern Alberta Portfolio Advance High Impact Opportunities Optimize Balance Sheet For Growth Positioned to pursue profitable growth strategy 5
2018 Forecast Capital Spending ($ millions) 2017 H1 2018 Forecast H2 2018 Forecast 2018 Forecast Total West Central Liquids-Rich Gas $65 14 gross (13.4 net) drills $8 1 gross (1.0 net) drills (2 frac s) $3 0 drills (1 frac) $11 1 gross (1.0 net) drills (3 frac s) Eastern $7 5 gross (4.3 net) drills $6 4 gross (4 net) drills Waterflood Infrastructure 10 recompletions $6 - $10 6-9 gross (5.3 8.3 net) drills 10 recompletions $12 - $16 10-13 gross (9.3 12.3 net) drills Total (1) $73 $14 $9 - $13 $23 - $27 (1) Additional Asset Retirement (ARO) spending of $2.0 to $2.5 million in 2018 (2017 - $2.3 million) Targeting 2018 capital funded from adjusted funds flow Monitoring gas prices to assess re-start of East Edson H2 drilling program 6
Average Daily Production (Boe/d) Line of Sight Growth Plan 14,000 12,000 10,000 8,000 6,000 4,000 2,000 2017 Avg 9,876 boepd Forecast Production 2018 Avg 11,500 boepd - Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018E Q2 2018E Q3 2018E Q4 2018E Gas Production Oil & NGL Growth-oriented Capital Plan 54% exit rate production growth (December 2016 vs December 2017) 2018 forecast average production growth of 17% year over year Optimizing Timing of Capital Program for Value 2018 Forecast reflects guidance released February 7, 2018 Prudently deferring East Edson spending to preserve value in low AECO gas price environment Peak production during winter months to maximize capture of highest commodity prices Possible summer shut-ins may shift portion of natural gas production profile to Q4 2018 Edson H2 2018 drilling program may be reinstated if AECO prices improve Forecast production per share growth of 17% year-over-year 7
Market Diversification Strategy Crude Oil Fixed 3% NGL - Other 2% NGL - Condensate 3% Malin 16% 2018 Price Exposure Net of Royalties (1) Crude Oil 8% Chicago 18% Michcon 7% AECO Fixed Price 27% Dawn 11% (1) As per guidance released February 7, 2018. (2) 2018 YTD Settled and Mark to Market April 4, 2018 = $25.7 million. Empress 5% Natural gas market shift to diversify portfolio Locked in term spreads and swapped back to Daily Index at five downstream delivery points Physical delivery at AECO NIT Receive Daily Index market price for each location, less published transportation and fuel costs, plus $0.02 USD/MMBtu premium 35 MMcf/d effective Nov 1, 2017; 40 MMcf/d effective April 1, 2018 5 year term Full Opportunity to manage pricing / hedge new markets Daily Index can be swapped to Monthly Index at any individual market to manage front month pricing Term hedges can be established to manage price at any individual market, for all or any portion of the delivery period Multiple advantages of spread strategy vs. contracting pipe capacity 5 year exposure vs. longer term generally required for contracted pipe capacity matches expected timing for AECO supply to re-balance in broader market No regulatory requirements or export permits required for US markets Credit efficient structure through physical delivery obligation at AECO Forecast to enhance funds flow in 2018 Estimated to enhance PMT netbacks in 2018 by ~$0.76/GJ on contracted volumes ($0.54/GJ blended across total 2018 natural gas volumes) Gas market diversification contracts forecast to provide significant premium prices over AECO with increased pricing stability. 8
$/Boe $/Boe Increasing Margins 35.00 35 30.00 25.00 20.00 30 Maintaining Margins despite 25 lower AECO 2018 forward strip 20 15.00 15 10.00 10 5.00 5-2012 2013 2014 2015 2016 2017 2018E - Operating Costs Transportation Costs Cash G&A Interest Royalites Revenue 1) 2018 Forecast reflects guidance released February 7, 2018 Increasing margins driven by: Reducing Costs Top quartile operating costs with East Edson concentration and 2016 sale of high fixed cost mature assets combined with infrastructure control, operatorship and low cost culture Reduced TCPL tolls through West Central Alberta production concentration Total cost structure decreased >17% in 2017 Additional reductions expected in 2018, driven by growing production across a largely fixed cost base Maximizing Revenue Targeting higher value production mix Capital timing for peak production during winter months, allowing for declines through Q2/Q3 Market diversification netback arrangement reduces AECO exposure to <30% after royalties 2018 cash costs (1) forecast at $13 - $14/boe, down >25% from 2017 Maintaining netbacks despite lower current AECO prices (1) See Non GAAP Measures advisory 9
Calendar 2018 WTI ($US/bbl) 2018 Projected Adjusted Funds Flow Sensitivities Projected 2018 Adjusted Funds Flow (1) ($ CAD millions) Calendar 2018 NYMEX Price ($US/MMbtu) $2.25 $2.50 $2.75 $3.00 $3.25 $3.50 $3.75 $45.00 21 23 25 27 29 31 33 $50.00 23 25 27 29 31 33 35 $55.00 25 27 30 32 34 36 38 $60.00 28 30 32 34 36 38 40 $65.00 30 32 34 36 38 40 42 $70.00 32 34 36 38 40 42 44 $75.00 33 35 38 40 42 44 46 1) Sensitivities assume non-aeco market price points adjust commensurately and the Calendar 2018 AECO basis and WCS differentials are fixed at (US$1.77)/MMbtu and (US$23.83)/bbl respectively. See February 7, 2018 news release Outlook for additional guidance assumptions. Adjusted funds flow sensitivities are comparable to cash flows from operating activities sensitivities. 2) The NYMEX, WTI, NYMEX to AECO basis differential, WCS prices and CAD/USD exchange rate assumptions for Calendar 2018, based on settled and forward average prices January 25, 2018, were US$2.98/MMbtu, US$63.54/bbl, (US$1.77)/MMbtu, (US$23.83)/bbl and 1.235 respectively. For every $0.25 USD/MMbtu widening (narrowing) in Cal 2018 AECO basis, adjusted funds flow increases (decreases) by $4.4 MM For every $5.00 USD/bbl widening (narrowing) in Cal 2018 WCS differential, adjusted funds flow decreases (increases) by $1.6 MM For every $0.01 increase (decrease) in Cal 2018 CAD/USD exchange rate, adjusted funds flow increases (decreases) by $0.9 MM Nov 10 Nov 10 Feb 7 Cal18 NYMEX ($US/MMbtu) 3.08 2.88 Cal18 WTI ($US/bbl) 56.59 $61.25 Cal18 AECO Basis ($US/MMbtu) (1.352) $(1.73) Cal18 WCS Differential ($US/bbl) (15.69) $(25.60) Cal18 $CAD/$USD exchange rate 1.269 1.249 Feb 7 2018 adjusted funds flow at current commodity prices ~ $0.56/share 10
STRATEGIC PRIORITY #1 GROW VALUE OF GREATER EDSON LIQUIDS-RICH GAS
Edson Activity Added 15 MMcf/d capacity at West Wolf 10-3 plant to bring area capacity to 78 MMcf/d Winter 2017/18 ERH program - longest well to date >3,400m horizontal length Pre 2017 2017 Q1 2018 H2 2018 2018 Drill ready 1 frac to be completed in Q4 2018 4 ERH wells ready to execute in H2 2018 if gas price improves 12
Edson Type Curves McDaniel YE 2017 TPP West Type Curve Economics (1) Price Deck McDaniel January 1/2018 Average (2) West TPP Type Curve (3) West TPP Low Type Curve (3) East TPP Type Curve (3) Capital (D,C & T) $ 4.5 MM NPV @ 10 % $ 3.5 MM ROR 45% F&D Capital Efficiency Payout $ 6.57/ boe $7,800 boe/d 2.1 Years Recycle Ratio 2.1 (1) Actuals and type curves adjusted to common 1,800m length by linearly adjusting completed length; Rate*1,800/(completed horizontal length (m)). All rates are raw gas and exclude associated liquids (2) Averages represent normalized moving average rate of all Perpetual wells rig released since Jan 2014. (3) East Edson East and West type curves derived from 2017 N1 51-101 McDaniel Proved Plus Probable (TPP Report) on reserves data (the N1 51-101 Report ) Year 1 Pricing Operating Costs Well Depth Lateral Length Type Curve 2P Reserves $2.13/ GJ (Aeco); $54.06/bbl NGL $1.57/ boe (first year) 4,350 M HZ; 2,625 TVD 1,700 Meters IP 7.0 MMcf/d 1 year exit rate 1.9 MMcf/d 11.75 bbl/mmcf NGL/condensate 4.1 Bcfe per well Well defined TPP type curves (1) provide reliable forecasts ERH wells length-adjusted to increase rate & reserves per well Year End 2017 Reserves incorporate improving capital efficiencies & lower operating costs, more than offseting impact of deteriorating natural gas prices 13
East Edson Wilrich Capital Efficiency 1) Capital efficiency = Cost to drill complete, equip and tie in/first 12 months average daily production, based on actual capital and average daily production to date (with McDaniel 2017 PDP forecast for wells onstream less than 12 months). The ERH estimate is based on future estimates of proven undeveloped locations from the McDaniel 2017 report. Continuous improvement in drilling & frac design driving strong capital efficiency & reduced future development capital 2017 - Monobore design proved up for 1,700 metre type curve length wells H2 2017/2018 Transitioning to: Optimized monobore design with consistent rig program and longer laterals Continually targeting further improvements in first 12 months capital efficiency Extended reach horizontal wells ( ERH ) targeting 2,200 to 3,400 metre lateral lengths Dissolvable frac balls, eliminating costs to drill out balls and seats Targeting further improvements in capital efficiency 14
Operating Cost ($M) Operating Cost ($/Boe) Top Quartile Operating Cost Structure 2,500 East Edson Operating Costs 14.00 2,000 12.00 10.00 1,500 8.00 1,000 6.00 500 4.00 2.00 0 0.00 Operating Costs Operating Costs ($/Boe) (1) (1) See February 7, 2018 news release Outlook for Operating Cost guidance assumptions Increasing production over fixed cost base driving top decile operating cost structure at East Edson of < $2.50/boe 15
STRATEGIC PRIORITY #2 GROW VALUE OF EASTERN ALBERTA PORTFOLIO
Eastern Alberta Mannville 8 Producing Mannville pools 6 Lloyd, 2 Sparky Q1 2018 production ~900 boe/d Access to Large Resource > 190 MMbbl Discovered Petroleum initially in place (1) 4.7 MMbbl produced to date (<3%) 2.9 MMbbl remaining TPP reserves (4% recovery factor) (1) Low cost HZ development $0.9 MM DC&T per well (1) Capital cost reduction of 30% materially enhances profitability in current commodity price environment Average expected initial rate ~50-120 bbl/d (1) 2017 Capital Program 4 (3.3 net) heavy oil wells 3 exploratory / 1 development) Waterflood Expansion 2018 Capital Program Q1 3 (3 net) wells (7 laterals) H2 up to 10 (9.3 net) wells (3 not shown) Continued waterflood expansion (1) Parameters as per 2017 NI51-101 McDaniel Report in accordance with COGE Handbook effective Jan 1, 2018. Recovery factor based on aggregate McDaniel TPP + Cum produced to date divided by aggregate DPIIP. Initial rates as per range in PPUD bookings. Expanded 2018 Capital Program targeting development drilling and waterflood projects forecast to grow heavy oil production 25% to 30% 17
Mannville Heavy Oil Drilling Inventory Well Economics Assumptions (1) Capital (D,C & T) $0.9 MM NPV @ 10 % $1.5 MM ROR 184 % 2018 Pricing (McDaniel Jan 2018 forecast) Operating Costs CAD$47.90/bbl wellhead heavy price WTI US$58.50/bbl, WCS CAD$51.90/bbl, Offset CAD$-4.00/bbl $6.03/boe (first year) & $13.83/boe (lifetime) F&D $8.35 / boe Average Well IP 100 bbl/d to 59 bbl/d in year 1 Payout 0.9 years Capital Efficiency (First Year) Recycle Ratio (First Year) $10,500/boe/d 3.9 Ultimate Recovery Royalties 100 Mbbl oil per well Mixed Crown (Modernized Royalty Framework) and Freehold Oil over shakers while drilling Sparky development pad HZ pad site (1) Mannville Heavy Oil P+PUD (Total Proved Plus Probable) reserve parameters as per 2017 N1 51-101 McDaniel Report on Reserves Data 11 (10.0 net) locations booked in McDaniel year end 2017 Unbooked Inventory of 31 (30.4 net) risked locations 18
Oil Rate, bbl/d Oil Rate, bbl/d Oil rate, bbl/d Mannville Heavy Oil Pools Waterflood Response 800 Upper Mannville I2I Pool 600 400 McDaniel YE 2017 Waterflood Wedge Volumes from Capital Spent To-Date F&D Recycle Ratio 200 Pool Capital To-Date ($MM) To-date (Nov 2017) (Mbbl) Ultimate (Mbbl) (1) To-date (Nov 2017) ($/bbl) Ultimate ($/bbl) (1) Current Netback ($/bbl) To-date (Nov 2017) Ultimate (Mbbl) (1) B $3.4 253 943 $13.44 $3.60 $26.50 2.0 7.4 0 1/1/2013 1/1/2015 1/1/2017 1/1/2019 Oil Rate Oil Base Forecast Oil Rate Without Infill McDaniel PPDP 2017 McDaciel TPP 2017 I2I $4.4 170 659 $25.85 $6.66 $26.16 1.0 3.9 Total $7.8 423 1,603 $18.43 $4.86 800 800 600 Upper Mannville B Pool - Regional Lloyd Mid 600 Upper Mannville B Pool - Regional Lloyd Lower 400 200 McDaniel YE 2017 400 200 McDaniel YE 2017 0 0 1/1/2013 1/1/2015 1/1/2017 1/1/2019 1/1/2013 1/1/2015 1/1/2017 1/1/2019 Oil Rate Oil Base Forecast McDaniel 2017 Oil Rate Oil Base Forecast McDaniel 2017 (1) Ultimate waterflood recovery evaluated by internal qualified reserves evaluator in accordance with COGE Handbook effective January 1, 2018 Waterflood response yielded positive technical revisions as expected and support continued investment 19
Waterflood and Enhanced Oil Recovery Scope Select Pools Currently Under Waterflood DPIIP (2) (MMbbl) Cumulative production to YE 2017 (MMbbl) TPP Reserves booked at YE 2017 (2) (MMbbl) Implied Recovery Factor (%) Sparky I2I (1) 25 0.5 0.4 4% Upper Mannville B 133 3.4 1.7 4% Upper Mannville T8T 11 0.2 0.5 7% Total 169 4.2 2.7 4% (1) Net working interest (2) DPIIP (Discovered Petroleum Initially In Place) and TPP Reserves, as per 2017 NI 51-101 McDaniel in accordance with COGE Handbook effective Jan 1, 2018 Internal forecasts suggest higher recoveries possible Large scope for increased reserves and value through continued waterflood management Further potential possible with polymer or other enhanced recovery processes in future 20
STRATEGIC PRIORITY #3 ADVANCE HIGH IMPACT OPPORTUNITIES
Bitumen Panny Bluesky Excellent reservoir quality in Bluesky homogeneous estuarine sand facies Panny LEAD Pilot Roads Natural Gas Pipeline Oil Well Effluent Pipeline Perpetual Gas Plant Perpetual Oil Sands Rights Other Perpetual Lands Low rate cold flow possible without solvent or thermal assistance Average pay thickness 11 m Low viscosity bitumen ~15,000 cp at 25 o C 50,000 cp at 11 o C reservoir temp Highly mobile at ~70 o C Panny Bluesky Resource Assessment 755 MMbbl DPIIP (1) Reservoir simulation model supports >50% recovery factor Resource sufficient to support >25,000 bbl/d commercial project for 20-25 years LEAD Pilot Phase 1 Phase 1 utilized a single horizontal well Heating commenced in October 2015 First production in March 2016 Cycle 2 May September 2016 Cycle 3 Solvent injection October 2016 Cycle 4 December 2016 May 2017 IETP funding reimbursed 30% of all capital and operations costs through YE 2016 Pilot Phase 2 Phase 2 utilizing solvent is currently being evaluated (1) DPIIP (Discovered Petroleum Initially In Place), evaluated by internal qualified reserves evaluator in accordance with COGE Handbook effective January 1, 2018 Experimenting with lower energy intensity extraction technologies compared to traditional steam-based thermal methods to mobilize bitumen 22
LEAD Process Technology Pilot Low Pressure Electro-Thermally Assisted Drive First stage of pilot single well Cyclic Heat Stimulation completed in Q2 2017 Electrical resistive heating and production in a single horizontal well to validate reservoir flow model and heater technology Two highly instrumented observation wells in close proximity to the horizontal heater well monitoring reservoir response Four cycles executed through 2016 and Q1 2017 of varying heat stimulation and solvent parameters Exceeded cumulative oil production expectations by >100% Second stage of pilot Solvent screening study underway; Alternative heat delivery systems being evaluated Second stage pilot design guided by first stage learnings and economic viability assessment to be scoped in H1 2018; Decision to proceed with second stage of pilot will follow Pilot results will drive full scale development potential assessment LEAD Pilot Stage 2 Configuration Top Gas Oil Heaters / Injectors Producer Conductive heating with water or solvent injection for mobility and pressure support 23
STRATEGIC PRIORITY #4 OPTIMIZE BALANCE SHEET FOR GROWTH
Balance Sheet (1) Net bank debt: $48 million Comprised of $32 million revolving bank debt and $16 million working capital deficiency Credit facility borrowing limit expanded by 62.5% to $65 million; Term extended until May 2019 Next borrowing limit redetermination scheduled prior to May 31, 2018 Term Loan: $45 million 8.1% interest rate; Matures March 2021 Senior Unsecured Notes: $32 million Series Face Value Coupon Rate Maturity Date Semi Annual Interest Payment dates 8.75% 2019 $14.5 million 8.75% July 23, 2019 January 23 & July 23 8.75% 2022 $17.9 million 9.75% to Jan 2018; 8.75% thereafter Jan 23, 2022 January 23 & July 23 TOU Share-based loan: $18 million 40% loan to value ratio established at funding Margin triggers reset if loan to value ratio exceeds 55% TOU Shares: 1.67 million @ $22.75/share: ($38 million) Net Debt = $ 106 million (1) As of December 31, 2017 2018 Capital funded by Adjusted Funds Flow 25
INVESTMENT THESIS POTENTIAL FOR MULTIPLE EXPANSION RELATIVE TO PEER GROUP COMPELLING DISCOUNT TO NET ASSET VALUE TORQUE TO GAS PRICE RECOVERY
Sum of the Parts Year-End 2017 Net Bank Debt Unbooked Inventory Unbooked Inventory (1) Net asset value per share based on 59.3 million shares outstanding. Reserve valuation based on NPV10% McDaniel reserves and pricing; Independent third party undeveloped land assessment as at December 31, 2017 (2) As per (1) above; Undeveloped land replaced with risk-discounted unbooked inventory in East Edson and Mannville only; West Central and Eastern Alberta Other unbooked inventory locations captured only through undeveloped land valuation outside East Edson and Mannville; Includes incremental TOU share value based on 12 month TOU analyst consensus target price of $30.44/share (3) As per (1) and (2) above; Unrisked unbooked inventory in East Edson and Mannville only; see oil and gas advisories in this presentation Future expect PPDP growth & TPP reserve replacement through cycling in of East Edson technical reserves from unbooked inventory YE 2017 year-over-year reserve growth: 100% PDP; 44% PPDP; 9% TPP (As per 2017 and 2016 McDaniel NI 51-101 Report) Year-End 2017 Reserve-Based NAV = $5.68/share 27
Key Investment Highlights High Quality Assets Asset base repositioning for resource-style and diversification successful Edson Wilrich liquids-rich gas inventory well-defined providing high capital efficiency growth Mannville heavy oil delivering diversified cash flow with material secondary recovery potential Prospects for short and long term growth from resource-style plays Increasing percentage of high netback production in asset mix Track Record of Operational Performance Execution and operational excellence in chosen strategies Multiple Levers to Manage Balance Sheet 2018 Capital funded by adjusted funds flow Additional potential for growth in available liquidity through TOU share price appreciation Pursuing further asset dispositions to continue to enhance liquidity Value Trading well below Reserve-Based Net Asset Value and attractively valued compared to other industry metrics Tremendous leverage to gas prices with asset mix and TOU exposure No net exposure to 2018 AECO gas price High impact value potential from medium to long term assets Spectrum of opportunities for value creation upon emergence from bottom of commodity price cycle 28
ADDITIONAL INFORMATION Sue Riddell Rose President & CEO Mark Schweitzer VP Finance and CFO info@perpetualenergy.com EMAIL 800.811.5522 TOLL FREE 403.269.4400 PHONE 403.269.4444 FAX 3200, 605 5 Avenue SW Calgary, Alberta Canada T2P 3H5 W W W. P E R P E T U A L E N E R G Y I N C. C O M 29
Forward Looking Statements This presentation contains forward-looking statements relating to Perpetual's business and operations that are based on management's current expectations, estimates and projections about its business and operations. Words and phrases such as "anticipates," "expects," "believes," "estimates," "projected," "future," "goals," "forecast," "plan," "opportunities," "upside," "will," "impact," "target," and similar expressions are intended to identify such forward-looking statements. Such statements include, but are not limited to, statements pertaining to: Perpetual's spectrum of opportunities that can be optimized through variable commodity cycles and anticipated value creation arising from such opportunities; Perpetual's top strategic priorities including reducing debt and restoring cash flow, growing value and scope of greater Edson liquids-rich gas, maximizing value of Eastern Alberta assets and advancing high impact opportunities; targeting additional asset sales for further balance sheet improvement; anticipated benefits of waterflood projects; reserve and resource estimates; projected economics for various projects and expenditures; and future capital expenditure levels. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward-looking statements. You should not place undue reliance on these forward-looking statements, which speak only as of the date of this presentation. Unless legally required, Perpetual undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise. Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are: inaccuracies in the estimated timing and amount of future production of natural gas and oil due to numerous factors including permit delays or restrictions, weather, equipment failures, delays or lack of availability, unexpected subsurface or geologic conditions, lack of equity or debt capital, increases in the costs of rented or contracted equipment, increases in labor costs, volumes of oil or gas greater or lesser than anticipated, and changes in applicable regulations and laws; unexpected problems with wells or other equipment, unexpected changes in operating costs and other expenses, including utilities, labor, transportation, well and oil field services, taxes, permit fees, regulatory compliance and other costs of operation; decreases in natural gas and oil prices, including price discounts and basis differentials; difficulties in accurately estimating the discovery, volumes, development potential and replacement of natural gas and oil reserves; the impact of economic conditions on our business operations, financial condition and ability to raise equity or debt capital; variances in cash flow, liquidity and financial position; a significant reduction in our bank credit facility's borrowing base; availability of funds from the capital markets and under our bank credit facility; our level of indebtedness; the ability of financial counterparties to perform or fulfill their obligations under existing agreements; write downs of our asset carrying values and oil and gas property impairment; the discovery of previously unknown environmental issues; changes in our business and financial strategy; inaccuracies in estimating the amount, nature and timing of capital expenditures, including future finding and development costs; the inability to predict the availability and terms of capital; issues with marketing of natural gas and oil including lack of access of markets, changes in pipeline and transportation tariffs and costs, increases in minimum sales quality standards for oil or natural gas, changes in the supplydemand status of gas or oil in a given market area, and the introduction of increased quantities of natural gas or oil into a given area due to new discoveries or new delivery systems; the impact of weather limiting or damaging operations and the occurrence of natural disasters such as fires, floods, hurricanes, earthquakes and other catastrophic events and natural disasters; the high-risk nature of drilling and producing natural gas and oil, including blow-outs, surface caterings, fires, explosions; the competitiveness of alternate energy sources or product substitutes; technological developments; changes in governmental regulation of the natural gas and oil industry potentially leading to increased costs and limited development opportunities; changes in governmental regulation of derivatives; developments in natural gas-producing and oil-producing countries potentially having significant effects on the price of gas and oil; the effects of changed accounting rules under generally accepted accounting principles and IFRS ; the amount of future abandonment and reclamation costs, asset retirement and environmental obligations; inability to execute strategic plans and realize projected economics, expectations and objectives for future operations and price risk management strategies; and the other risk factors identified in our most recent financial statements and management's discussion and analysis and Annual Informational Form and our other filings on SEDAR. Unpredictable or unknown factors not discussed herein also could have material adverse effects on our business and operations and on the forward-looking statements contained herein. 30
Non GAAP Measure Advisories NON-GAAP MEASURES: The terms adjusted funds flow, adjusted funds flow per share, adjusted funds flow per boe, available liquidity, cash costs, gas over bitumen revenue, net of payments, net working capital deficiency (surplus), net debt and net bank debt, operating netback, realized revenue and enterprise value used in this presentation are not recognized under GAAP. Management believes that in addition to net income (loss) and net cash flows from operating activities as defined by GAAP, these terms are useful supplemental measures to evaluate performance. Users are cautioned however that these measures should not be construed as an alternative to net income (loss) or net cash flows from operating activities determined in accordance with GAAP as an indication of Perpetual s performance and may not be comparable with the calculation of similar measurements by other entities. Additional information on these Non-GAAP measures, including reconciliations to applicable GAAP measures, are included in the Company s most recently filed Management Discussion and Analysis and may be accessed through the SEDAR website (www.sedar.com) or Perpetual s website (www.perpetualenergyinc.com). Adjusted funds flow: Management uses adjusted funds flow and adjusted funds flow per boe as key measures to assess the ability of the Company to fund capital expenditures, expenditures on decommissioning obligations and meet its financial obligations. Adjusted funds flow is calculated based on cash flows from operating activities excluding changes in non-cash working capital and expenditures on decommissioning obligations as Perpetual believes the timing of collection, payment or incurrence of these items involves a high degree of discretion. Expenditures on decommissioning obligations may vary from period to period depending on capital programs and the maturity of our operating areas and are managed through our capital budgeting process which considers available adjusted funds flow. To make reported adjusted funds flow more comparable to industry practice, the Company reclassifies certain exploration and evaluation costs from operating to investing activities in the adjusted funds flow reconciliation. These exploration and evaluation costs include dry hole costs in addition to geological and geophysical costs, which are expensed in the period incurred. The Company has also reclassified the change in gas over bitumen royalty financing from financing to operating activities in the calculation of adjusted funds flow, in order to present these payments net of gas over bitumen royalty credits. These payments are indexed to gas over bitumen royalty credits and are recorded as a reduction to the Corporation s gas over bitumen royalty financing obligation in accordance with IFRS. Additionally, the Company has excluded payments of restructuring costs associated with the disposition of the Shallow Gas Properties, which management considers to not be related to cash flow from operating activities. Restructuring costs include employee downsizing costs and surplus office lease obligations. Adjusted funds flow per share is calculated using the same weighted average number of shares outstanding used in calculating earnings per share. Adjusted funds flow per boe is calculated as adjusted funds flow divided by total production sold in a period. Adjusted funds flow is not intended to represent net cash flows from operating activities calculated in accordance with IFRS. Available liquidity is defined as Perpetual s Credit Facility Borrowing Limit, plus TOU share investment, less borrowings and letters of credit issued under the Credit Facility and TOU share margin loans. Management uses available liquidity to assess the ability of the Company to finance capital expenditures, expenditures on decommissioning obligations and meet financial obligations. Cash costs: Management believes that cash costs assist management and investors in assessing Perpetual s efficiency and overall cost structure. Cash costs are comprised of royalties, production and operating, transportation, general and administrative and cash finance expenses. Gas over bitumen revenue, net of payments: Gas over bitumen revenue, net of payments, includes gas over bitumen royalty credits less monthly payments on the gas over bitumen royalty financing. This is used by management to calculate the Corporation s net realized gas over bitumen revenue to reflect the substantive monetization of the future gas over bitumen royalty credits. Net debt and net bank debt: Net bank debt is measured as current and long-term bank indebtedness including net working capital deficiency (surplus). Net debt includes the carrying value of net bank debt, the principal amount of the Term Loan, the principal amount of TOU share margin loans and the principal amount of Senior Notes reduced for the mark-to-market value of the TOU share investment. Net bank debt and net debt are used by management to analyze borrowing capacity. Net working capital deficiency (surplus): Net working capital deficiency (surplus) includes total current assets and current liabilities excluding short-term derivative assets and liabilities related to the Corporation s risk management activities, current portion of gas over bitumen royalty financing, TOU (described below) share investment, TOU share margin loans and current portion of provisions. Operating netback: Perpetual considers operating netback an important performance measure as it demonstrates its profitability relative to current commodity prices. Operating netback is calculated by deducting royalties, operating costs, and transportation from realized revenue. Operating netback is also calculated on a per boe basis using average boe production sold for the period. Operating netback on a per boe basis can vary significantly for each of the Company s operating areas. Realized revenue: Realized revenue is the sum of realized natural gas revenue, realized oil revenue and realized NGL revenue which includes realized gains (losses) on financial natural gas, crude oil and foreign exchange contracts but excludes any realized gains (losses) resulting from contracts related to the disposition of the Shallow Gas Properties. Realized revenue, excluding foreign exchange contracts is used by management to calculate the Corporation s net realized commodity prices taking into account monthly settlements on financial crude oil and natural gas forward sales, collars and basis differentials. These contracts are put in place to protect Perpetual s adjusted funds flow from potential volatility in commodity prices, and as such, any related realized gains or losses are considered part of the Corporation s realized price. Enterprise value: Enterprise value is equal to net debt plus market value of issued equity and is used by management to analyze leverage. Enterprise value is not intended to represent the total funds from equity and debt received by the Corporation upon issuance. 31
Oil and Gas Advisories OIL AND GAS ADVISORIES: The presentation refers to F&D (finding and development costs), ROR (rate of return), payout and recycle ratio which have been prepared by management and are used to measure performance. These terms do not have standardized meanings or standard calculations and are not comparable to similar measures used by other entities. In this presentation internal rate of return refers to the discount rate that makes the net present value of all cash flows of a project equal zero and payout refers to the time required to pay back the capital expenditures (on a before tax basis) of a project. The presentation also refers to capital efficiency which is defined as a type of capital efficiency that measures the cost to add an incremental barrel of flowing production. Specifically, for the average production efficiencies of our plays, Perpetual uses the total actual/projected drill, complete and tie-in capital divided by the total of the well initial twelve-month production rate. RESERVE ESTIMATES: The reserves estimates contained in this presentation represent our gross reserves as at December 31, 2017 and are defined under NI 51-101, as our interest before deduction of royalties and without including any of our royalty interests. It should not be assumed that the present worth of estimated future net revenues presented in the tables above represents the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserves estimates of our crude oil, NGL and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and NGL reserves may be greater than or less than the estimates provided herein. All future net revenues are estimated using forecast prices, arising from the anticipated development and production of our reserves, net of the associated royalties, operating costs, development costs, and decommissioning obligations and are stated prior to provision for finance and general and administrative expenses. Future net revenues have been presented on a before tax basis. Estimated values of future net revenue disclosed herein do not represent fair market value. The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. Our estimated reserve based NAV is based on the estimated NPV10 of all future net revenue from our proved plus probable reserves, before tax, as estimated by McDaniel at year-end, with the estimated value of our undeveloped land, and less net debt. Common share values in our NAV per share metric are calculated using common shares outstanding, net of shares held in trust. Our risked and unrisked NAV includes Unbooked inventory comprised of 47 gross (40.4 net) drilling locations at East Edson and 31 gross (30.4 net) drilling locations at Mannville, for which reserves have not been assigned. VOLUME CONVERSIONS: Barrel of oil equivalent ( boe ) may be misleading, particularly if used in isolation. In accordance with National Instrument 51-101 ( NI 51-101 ), a conversion ratio for natural gas of 6 Mcf:1 bbl has been used, which is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In addition, utilizing a conversion on a 6 Mcf:1 bbl basis may be misleading as an indicator of value as the value ratio between natural gas and crude oil, based on the current prices of natural gas and crude oil, differ significantly from the energy equivalency of 6 Mcf:1 bbl. 32
APPENDIX
Diversified Portfolio for Value Creation Edson Wilrich Greater Edson secondary zones Columbia/Brazeau Waskahigan Duvernay Deep Basin & Wilrich exploration Liquids- Rich Gas Shallow Gas Mannville & Panny conventional shallow gas Mannville Viking shallow shale gas Tight conventional exploration Bitumen Heavy Oil Panny Bluesky Liege Grosmont & Leduc Bitumen land bank Mannville Mannville waterflood/eor Heavy oil exploration Spectrum of opportunities to optimize value through variable commodity cycles Short term investment as well as longer term value opportunities 34
Debt Repayment and Liquidity Profile 60% Debt Repayment Profile 12/31/2017 80 50% 40% 36% 49% 70 $62.9 MM 60 50 $46.2 MM 30% 40 20% 10% 15% 30 $18.5 20 MM 10 0% 0 < 1 Year > 1 Year < 3 Years > 3 Years TOU Loan Bank Debt Senior Notes Term Loan Danigs Available liquidity (1) at Year-End 2017 of $49 million Comprised of available bank line plus TOU share investment, net of TOU share based loan (1) See Non-GAAP Measures advisory in this presentation 2017 financings strengthened debt repayment profile and secured funding for growth plans while enhancing liquidity 35
Boe/d Greater Edson Liquids-Rich Gas Wilrich Play Performance Cumulative Production (MBoe) 14,000 25,000 2014: East Edson JV Royalty deal Sold 5.6 MMcf/d plus associated liquids for $120 MM investment 12,000 10,000 8,000 6,000 4,000 2,000-2011 2012 2013 2014 2015 2016 2017 2018E East Edson West Edson 20,000 15,000 10,000 5,000-2015: Growth driven by JV Royalty sale commitments Constructed new 30 MMcf/d West Wolf Lake plant on stream July 2015 & expanded to 45 MMcf/d September 2015 Drilled to fill East Edson facilities and transportation contracts 60 MMcf/d plus NGL s: 45 MMcf/d at West Wolf & 15 MMcf/d WI owner gas at Rosevear 2016: Preserving value in low gas price environment 1 drill only and allowed for natural declines Shut-in sour volumes through third-party facility 2017: Drill to grow production to expanded TCPL transport and plant capacity 1 rig Wilrich program drilling to fill existing infrastructure & meet new transport in December 2017 (originally scheduled for April 2018) Add 15 MMcf/d compression at West Wolf for area capacity of 78 MMcf/d 2018: Maintain production and optimize value through seasonality Allow natural declines and ramp up production for stronger winter month pricing 2019: Sustain with Wilrich and Secondary Zone Evaluation Advance evaluation of secondary Viking, Notikewin, Fahler & Gething horizontal development potential supported by 3D seismic Sold to Tourmaline April 1 / 15 for 6.75 million TOU shares estimated at $258 million (~5,750 Boe/d) Infrastructure and inventory in place for profitable growth 36
Conventional Shallow Gas Belly River Viking Grand Rapids Lower Mannville Pre Cretaceous Unconformity Conventional shallow gas asset base characteristics Primarily Mannville Area remaining post shallow gas disposition Cretaceous sweet shallow gas <800m Current production ~ 5.8 MMcf/d Base declines < 10-15% Multiple stacked zones and play types sourcing recompletion inventory Extensive plant & pipeline infrastructure with unutilized capacity High fixed operating costs driven by municipal taxes and low volume wells Marginal current netbacks highly leveraged to improving natural gas prices Operational Focus Facility optimization projects, workovers and uphole recompletions payout in months Low cost production and reserves adds 23 recompletions/workovers/optimizations added 1.7 MMcf/d since Dec 2016 Drive fixed and variable operating cost reductions Metering, municipal taxes, scaled-back operational approach, execute ARO Further reduce asset retirement obligation project costs Prospecting for tight reservoirs in high resource potential traps for development with horizontal wells & multi-stage frac technology Value optimization focuses on intense program approach to recompletion/workovers combined with abandonment and reclamation projects 37
Viking Shallow Shale Gas Perpetual Viking Horizontal Test Well Tight Viking Fairway Vertical Tight Viking Wells Permeable Viking Wells Outline of Tight Viking Area Perpetual Land Perpetual Pipelines Perpetual 4-27 Gas Plant Viking Tight Gas Resource Play ~80 sections of P&NG rights on trend Type curves developed from tight Viking production from vertical wells in conjunction with detailed core analysis and inflow diagnostic testing Limited dataset for Viking gas horizontals Potential for horizontal development at 2-4 wells per section Reserves 1.4 Bcf PPNP (1) booked in recompletions Proven development & capital commitment could drive substantial future bookings 2017 Executed 1 Viking Horizontal pilot Well partially completed; further evaluation work pending gas price recovery Executed 1 Colorado Horizontal well Results to date disappointing 2018 Encouraging risk/reward at > $3/GJ gas price Evaluating opportunities to drive improved production, reserves and capital efficiencies (1) 2017 NI 51-101 McDaniel Optionality on large resource in place with low variable operating cost Risk managed investment required to unlock technically for commercial development 38
Bitumen R9 R5 R1W5 R21 R17 R13W4 T98 T95 Perpetual OS Leases Overriding Royalty Lands Perpetual Panny Pilot Experimental Primary Projects Thermal Projects 301 net sections (192,416 net acres) of oil sand leases Various formation targets and ultimate recovery methods 6 potential project areas with varying potential Over 1.3 billion bbls DPIIP (1) at Liege and Panny Sold 37 net sections of select oil sands leases for $6.1 million in Q1 2016 Retained 1% GORR (1) DPIIP (Discovered Petroleum Initially In Place), evaluated by internal qualified reserves evaluator in accordance with COGE Handbook effective January 1, 2018 Bitumen lands represent large resource in place and material option value 39
Transformational Transactions Warwick Gas Storage Sale: (May 2016) Sold remaining 30% partnership interest ($23 million) Senior Notes Swap: (May 2016) Retired Senior Notes via swap for 4.4 MM TOU shares ($214 million) Shallow Gas Disposition: (Oct 2016) Vast majority of Eastern Alberta shallow gas assets sold Oct 1/16 (nominal proceeds - Eliminated negative funds flow assets) Reduced asset retirement obligation ($128 million) Retained gas price upside exposure on ~90% of forecast production for 2 years Financing Transactions: (H1 2017) AIMCo 8.1% 4 year Term Loan & 5.4 MM warrants ($45 million) Equity issuance 5.1 MM shares & 1.1 MM warrants ($9 million) Senior Notes Management: (H1 2017) Senior notes maturity extension to Jan 2022 ($17.9 million) Early redemption of 2018 Senior Notes in April 2017 ($27.6 million) Optimized Credit Facilities (H2 2017) Increased reserve-based credit facility limit to $65 million capacity Refinanced TOU share margin loan for lower cost Positive Impact: High graded asset base for increased netbacks Established sustainable cost structure, including $6MM/year of reduced G&A Strengthened balance sheet with 85% reduction in debt through $240 million repayment of senior notes and $67 million of new funding Secured liquidity to execute growth-oriented capital program Enhanced flexibility to manage TOU share investment Improved debt maturity profile Transformational transactions in 2016 & 2017 YTD position Perpetual for profitable growth and value creation 40
Shallow Gas Disposition October 1, 2016 Nominal proceeds + 2 year call option Deferred Purchase Price through 2 year call on AECO gas price > $2.81/GJ for 33,611 GJ/d Metrics Impact Production: (35.5 MMcfe/d) Adjusted Funds Flow: $5-10 MM/year TPP Reserves: (14 MMboe) NPV(10) TPP: $6.5 MM Well Count: 2,952 to 495 ARO Liabilities (excl salvage): $123 MM LLR: 2.1 to 3.8 Net Asset Value (PV10): $28.5 MM to $35 MM Retained Assets West Central (including East Edson) Mannville (shallow gas & heavy oil) Panny (shallow gas & bitumen) Oil sands leases (& area P&NG) Other exploration acreage Gas over Bitumen royalty credit income stream Disposed Assets 2,221 net wells 584 producing, 910 shut-in, 727 abandoned 353,777 net undeveloped acres Accretive to Perpetual on all value metrics & 2 year gas price upside retained Material decrease in production & reserves offset by increase in cash flow & value 41