C O R P O R A T E P R E S E N T A T I O N F I N A N C I N G T R A N S A C T I O N S F E B R U A R Y 1 7, 2017 BOLD IDEAS FOR ENERGY

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1 C O R P O R A T E P R E S E N T A T I O N F I N A N C I N G T R A N S A C T I O N S F E B R U A R Y 1 7, 2017 BOLD IDEAS FOR ENERGY 1

2 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 supply-demand 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. 2

3 Financing Transactions Feb 17, 2017 Credit Facility Increased borrowing limit from $6 million to $20 million Extended maturity to October 31, 2017 Subject to borrowing base redetermination May 31, 2017 Second Lien Senior Secured Term Loan $45 million available in 2 draws Initial Drawdown: $35 million at closing expected in early March 2017 Delayed Drawdown: $10 million prior to Nov 30, % annual interest rate Second Lien Units include 120 warrants per $1,000 face value (5.4 million warrants) 4 year term Matures March 2021 Equity Private Placement $9 million - Equity Units comprised of 5.1 million PMT shares and 0.21 warrants/share 50% Insiders and existing shareholders; 50% Second Lien lender Priced at market closing price for PMT commons shares on February 16, 2017 ~1.08 million warrants priced at closing in early March 2017 Embedded option value of warrant offsets lack of discount to market upon issuance Warrants Terms identical for warrants attached to second lien financing and equity private placement 120 warrants for every $1,000 face value of committed capital (equity or term debt) Exercise set at closing at 45% premium to 10 day VWAP prior to closing 3 year term expires March 2020 PMT option to require exercise if VWAP exceeds Exercise Price for 60 consecutive calendar days New capital availability of $68 million provides ample liquidity to execute 2017 & 2018 drilling programs and enhances flexibility to manage future debt maturities 3

4 Post Transactions Balance Sheet (Year-End 2016 adjusted for 2017 transactions) Net bank debt: ($ 38 million) Pro forma year-end 2016 working capital Includes $9 million in proceeds from equity private placement Borrowing base capacity of $20 million Second Lien Facility: $35 million $45 million capacity Remaining $10 million draw required prior to November 2017 Unsecured Senior Notes: $60.6 million Note Exchange shifted maturity for $17.4 million to January 2022 Same terms as existing notes with interest rate increased to 9.75% for first year only Series Face Value Current Market Value Coupon Rate Maturity Date Semi Annual Interest Payment dates 8.75% 2018 $27.5 million $27.2 million 8.75% March 15, 2018 March 15 & September % 2019 $15.7 million $15.5 million 8.75% July 23, 2019 January 23 & July % 2022 $17.4 million $17.4 million 8.75% Jan 23, 2022 January 23 & July 23 TOU Share-based loans: $35.9 million 1.57 million TOU shares pledged as collateral to the following arrangements: $18.9 million financing arrangement secured by 0.89 MM TOU shares Includes put option at strike price of $21.14/TOU shares; Matures August 1, 2017 $17 million margin loan secured by 0.68 MM TOU shares Includes put option at strike price of $27.38/TOU shares ; Matures November 14, million TOU shares unpledged TOU Shares: 1.67 $31.50/share = ($53 million) Total net debt less TOU share value = $ 41 million 4

5 Liquidity Pre-Financing Transactions Post-Financing Transactions ($ millions) Year End 2016 (Pro forma TOU share adjustments) (2) Capacity Available Liquidity Year End 2016 (Pro forma TOU share adjustments & Financing Transactions) (2) Capacity Available Liquidity Net bank debt (1)(2) (38) Second Lien Facility Senior Notes TOU Share-based financing arrangements / Unpledged TOU Shares (3) Total TOU Shares (53) (53) Total, including illustrative sale of TOU Shares (4) Bank debt, net of working capital; Pre-financing transactions roll forward from year-end 2016, excluding Q1 changes in working capital million total TOU shares (0.1 million unpledged); TOU shares at $31.50/share (Feb 15, 2017 market close) 3. Illustrative capacity and liquidity through sale of unpledged TOU Shares only 4. Illustrative capacity and liquidity assuming sale of 1.67 million TOU shares and settlement of TOU share-based loans Further optimization of balance sheet possible through full or partial repayment of TOU share-based loans, senior notes or combination thereof 5

6 Use of Proceeds Fund 2017 Capital Program $69 million capital program, including timing adjustments from Q % directed to East Edson drilling for 53% forecast growth in year over year exit rate production 10% focused at Mannville targeting Q1 heavy oil exploration and follow-on Q3 development 5% funding for Eastern Alberta shallow gas recompletion program and shallow shale gas pilot Other General Corporate Purposes Repayment of TOU-Share based Loans Outstanding TOU Share-based loans of $35.9 million Early repayment would include recovery of value from underlying embedded PUT options Enhances optionality to optimize value of TOU shares Future repayment of Senior Notes Enhanced future capital spending, as appropriate Priorities include funding 2017 capital program and managing short-term debt maturities 6

7 2017 Capital Budget 2017 H1 Forecast 2017 H2 Forecast 2017 Total West Central Liquids-Rich Gas $ 25.0 MM 5 gross (5.0 net) wells (complete 1 Q drills and 4 Q drills) $ 30.6 MM 8 gross (8.0 net) wells $ 55.6 MM Mannville Heavy Oil $ 4.0 MM 4 gross (3.3 net) wells $ 4.0 MM 4 gross (4.0 net) wells $ 8.0 MM Eastern Shallow Gas and Other $ 2.9 MM 9 recompletions 1 gross (1.0 net) wells complete 2 Viking/Colorado drills) $ 0.7 MM $ 3.6 MM Total $ 31.9 MM $ 35 MM $ 67.2 MM Includes timing related carry forward from Q Excludes 2017 ARO spending of up to $4.0 million Financing transactions provide certainty for funding drilling program initiated in Q to restore production levels and re-establish funds flow growth 7

8 Average Daily Production (Boe/d) Line of Sight Growth Plan 16,000 Total Production 14,000 12,000 10,000 8,000 6,000 4,000 2,000 - Q Q Q Q Q Q Q Q Q Q to Q % forecast production growth over 2 years Front end loaded with >60% exit rate production growth (December 2017 over December 2016) 44% per share growth assuming post-financing transactions basic shares outstanding Fully funded capital program at current strip prices Operations focus at East Edson and Mannville improves per unit cost structure Unit operating costs < $4.00/boe Forecast Gas Production Forecast Oil & NGL Expect continued reserve replacement with cycling of Edson technical reserves from inventory Strong growth in funds flow and PDP value at current strip pricing to support future credit facility borrowing base capacity Forecast exit rate production per share growth year over year of ~60% in

9 Perpetual Energy Inc. Current (1) Pro forma Financing Transactions (1) Common Shares o/s 53.7 million 58.8 million (6)(7) Management ownership ~49% 47-49% Share price (2) $ 1.75 $ 1.75 Market capitalization $ 94 million $ 103 million Total net debt (3) $ 50.5 million $41.5 million Net bank debt (3) $ 6 million ($ 38) million Loans secured by TOU shares (4) $ 36.5 million $ 36.5 million Second Lien Facility (5) - $ 35 million Senior unsecured notes $ 61 million $ 61 million TOU Shares million (4) ($ 53 million) ($ 53 million) Enterprise value $ million $ million (1) Pro forma year end 2016 working capital (2) February 16, 2017 market price (3) Includes bank debt, net of working capital at year end 2016 but excludes changes in working capital from year-end 2016 (4) Secured by 1.57 MM TOU shares; 0.1 MM unpledged; Market price Feb 15, 2017 $31.50/share (5) $45 million available at closing ; Initial draw $35 million, Second draw of $10 million prior to November 30, 2017 (6) Assumes $9 million equity issuance at market; Priced at market close price Feb 16, 2017 (7) Fully diluted shares outstanding will include 6.48 million warrants with exercise price to be set at 45% premium to 10 day VWAP preceding closing expected early March

10 Operating profile Eastern Alberta Conventional shallow gas Mannville heavy oil Bitumen Viking/Colorado shallow shale gas Deep Basin Edson Wilrich Multi-zone liquids-rich gas Tight oil & gas exploration Production (1) Natural Gas Oil and NGL P+P Reserves (2) 8,100 boe/d 40 MMcf/d 1,400 bbl/d 61.3 MMboe LIQUIDS-RICH GAS East Edson Other Deep Basin SHALLOW GAS Legacy conventional assets, Tight shallow gas HEAVY OIL Mannville BITUMEN Panny, Liege, Other Reserve to Production Ratio (P+P) (RLI) (1) Bitumen (3) Tourmaline Oil Corp. Shares 1.67 million (4) (1) Q Estimated (2) Year end 2016 (3) Internal contingent resource estimate (4) Market price of ~$31.50/TOU share 21 Years 399 MMbbl ~$ 53 million 10

11 Diversified Portfolio for Value Creation Edson Wilrich Greater Edson secondary zones Columbia/Brazeau Deep Basin & Wilrich exploration Liquids- Rich Gas Shallow Gas Mannville & Panny conventional shallow gas Mannville Viking/Colorado 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 11

12 2017 Strategic Priorities Grow Value of Greater Edson Liquids-Rich Gas Optimize Value of Eastern Alberta Assets Advance High Impact Opportunities Optimize Balance Sheet For Growth Strategic priorities focus our activities 12

13 KEY PRIORITY #1 GROW VALUE OF GREATER EDSON LIQUIDS-RICH GAS

14 Edson Wilrich Liquids rich Gas PERPETUAL To Rosevear Plant (15% WI) Pipeline To Edson Deep Cut Plant West Wolf Lake 10-3 Gas Plant Capacity 45 MMcf/d Compressor Capacity 30 MMcf/d Wilrich Rights East Edson JV Outline Pre 2014 Drill 2014 Q Q Q H Inventory of 145 (134.7 net) locations of which 76 (73.7 net) booked in reserve report Optimal development scenario set at ~400m inter-well spacing

15 West Edson Transaction Legacy of TOU Shares Swap of West Edson property for 6.75 million Tourmaline Shares Mark to Market at April 1, 2015 close ~ $258 million 24 MMboe of reserves 7.2 MMboe (29%) proved and probable developed producing 16.8 MMboe undeveloped reserves requiring ~$124.5 million of future development capital over 7-10 years 5,750 boe/d of production (95% gas) 2015 negative funds flow impact of ~$15 - $20 million Neutral to reserve-based NAV at Jan 1, 2015 discounted at 10% Transaction Rationale Maintain upside potential in West Edson but also well-funded, growth-oriented Alberta Deep Basin and BC Montney portfolio through TOU shares Provide liquidity and manage risk while maintaining exposure to improving commodity natural gas macro-environment over next two to three years Bolstered ability to manage future debt obligations Enhanced borrowing capacity relative to West Edson reserves (20% proved producing) Enhanced ability to manage downside commodity price risk Reduced net debt, considering TOU shares as a direct offset Financial Flexibility and Liquidity Utilized to reduce outstanding debt over past 2 years 4.4 million TOU shares swapped for $215 million Senior Notes 0.68 million sold to further reduce outstanding debt obligations Remaining TOU shares providing flexibility and liquidity to fund capital programs to capture inherent value Realized $236 million for debt reduction on 5.1 million TOU shares sold/swapped Remaining holdings 1.67 million MTM value of ~$53 million 15

16 Boe/d Cumulative Production (MBoe) Greater Edson Liquids-rich Gas Play Performance 14,000 16, : 40% net production growth Driven by West Edson expansion from 15 to 30 MMcf/d net Ramp up to fill existing East Edson facilities with JV drilling 12,000 10,000 8,000 6,000 14,000 12,000 10,000 8, : 136% net production growth Growth despite swap of West Edson (30 MMcf/d net plus NGL s) Constructed new 30 MMcf/d West Wolf Lake plant on stream July 2015 Expanded East Edson plant to 45 MMcf/d September 2015 Drilled to fill East Edson facilities and transportation contracts Improved results required 5 less wells in 2015 than forecast to achieve capacity 2016: Preserving Value in low gas price environment 1 Q1 drill and Q3 frac and tie-in only Shut-in of negative cash flow sour volumes through third-party facility 4,000 6,000 4, : Grow to fill existing plant capacity 1 rig Wilrich program drill to fill existing infrastructure 60 MMcf/d plus NGL s: 45 MMcf/d at West Wolf & 15 MMcf/d WI owner gas at Rosevear 2, E East Edson 2, : Grow to meet TCPL capacity growth Continue 1 rig program to meet 75 MMcf/d transportation commitment Add 15 MMcf/d capacity at West Wolf plant or utilize existing compressor and non-owner processing capacity at Rosevear Secondary Viking, Notikewin and Fahler horizontal development potential supported by 3D seismic exploration West Edson Infrastructure and inventory in place for continued growth 16

17 East Edson Type Curves Projected Economics per SW Drilling Location Capital (D,C & T) $ 4.3 MM McDaniel SW Type Curve McDaniel NW Type Curve McDaniel NE Type Curve Average of wells since % ROR F&D Capital Efficiency Payout Recycle Ratio 3.1 $ 5.4 MM 115% BT $ 6.39 / boe $7,200 boe/d 1.0 Years Assumptions (McDaniel YE Jan1/17 Pricing) Year 1 Pricing Operating Costs Well Depth Type Curve 2P Reserves $3.22/ GJ (Aeco) $50.91/bbl NGL $1.86/ boe (first year) 4,350 M HZ; 2,625 TVD IP 7.0 MMcf/d 1 year exit rate 2.0 MMcf/d bbl/mmcf NGL/condensate 4.1 Bcfe per well Strong performance drove McDaniel Year-End 2016 SW type curve IP up 8% while 2P recoverable reserves/type curve well increased by 21% 17

18 Top Quartile Operating Cost Structure Top Quartile Operating Cost Structure of <$3.00/boe 18

19 Gas Rate (MMcf/d) Greater Edson Production Growth 90,000 80,000 70,000 East Edson JV spending ramp up West Edson Swap for TOU Shares East Edson New Plant start-up Greater Edson Daily Production Decision to defer capital spending in 2016 One rig drilling program commenced in Q ,000 50,000 40,000 30,000 20,000 10,000 - East Edson Base Production West Edson Edson Forecast Production TCPL Transportation East Edson JV spending of $120 Million in 2014 and 2015 GORR of 5.6 MMcf/d of production to JV Partner Majority of PMT 2017 & 2018 growth driven by East Edson Plan to double production from Q to match infrastructure capacity & transport 19

20 KEY PRIORITY #2 OPTIMIZE VALUE OF EASTERN ALBERTA ASSETS

21 Eastern Alberta Conventional Heavy Oil 8 Producing Mannville pools* 6 Lloyd, 1 Sparky, 1 Basal Quartz > 136 MMbbl Original Oil in Place > 6 5% recovery factor Current production ~ 1,100 bbl/d Low exposure HZ development $0.75 $0.85 MM single or dual lateral HZ well Capital costs reduced by 30% material enhances profitability in current commodity price environment Average initial rate ~80 bbl/d Q / Q Capital Drill 4 heavy oil wells 3 exploratory / 1 development De-risk up to 29 potential inventory locations Up to $1.4 MM of waterflood expansion Additional 4-7 injection conversions *6 of 8 pools shown Drilling recommenced in Q after 2 year hiatus for oil price recovery & waterflood assessment 21

22 Mannville Heavy Oil Value Potential Projected Economics Per Well (unrisked) Assumptions Development Exploration Capital (D,C & T) $0.7 MM $0.9 MM 10 % $1.0 MM $2.2 MM ROR 109% 100% F&D $9.61 / Boe $7.66 / Boe Payout 1.2 year 1.4 Year Capital Efficiency $15,700/Boe/d $16,400/Boe/d Recycle Ratio Pricing (McDaniel Jan 2017 forecast) Operating Costs Average Well 2P Reserves Royalties $CA 49.70/bbl wellhead heavy price WTI $US 55.00/bbl, WCS $CA 53.70/bbl, Offset $CA -4.00/bbl $7.31/Boe (first year) & $16.10/Boe (lifetime) Development: IP 60 bbl/d to 40 bbl/d after year 1 Exploration: IP 106 bbl/d to 42 bbl/d after year 1 Development Infill: 75 Mbbl per well Exploration: 115 Mbbl per well Mixed Crown (Modernized Royalty Framework) and Freehold (variable) Oil over shakers while drilling Sparky development pad HZ pad site Reduced drilling capital re-established robust economics Highly profitable in oil price recovery 22

23 Waterflood Pilot Response - Mannville I2I Working Interest 66.7% OOIP: 38 MMbbl Cum Prod n + McDaniel P+P: 1.5 MMbbl (4% recovery factor) 19 Horizontals drilled to date 11 infill locations remain Implementing Waterflood 7 injectors converted in 2013/2014; 1 injection conversion Mannville I2I Waterflood Pool Sparky Mid Type Log 100/ W4/00 > 24 % DENSITY POROSITY 6 m OIL PAY Sparky Mid Sand Waterflood injection optimization showing increasing oil response

24 Oil Rate, bbl/d Inj Start - Sept 2015 Oil Rate, bbl/d Inj Start - Sept 2014 Inj Start - Aug 2015 Positive Waterflood Response 300 Single Pattern Example in Mannville B Pool - Regional Lloyd Lower Internal Forecast McDaniel YE Base Forecast 0 1/1/2013 7/1/2013 1/1/2014 7/1/2014 1/1/2015 7/1/2015 1/1/2016 7/1/2016 1/1/2017 7/1/2017 1/1/ Single Pattern Example in Mannville B Pool - Regional Lloyd Middle Internal Forecast McDaniel YE Base Forecast 0 1/1/2013 7/1/2013 1/1/2014 7/1/2014 1/1/2015 7/1/2015 1/1/2016 7/1/2016 1/1/2017 7/1/2017 1/1/2018 Positive initial waterflood response in Mannville B pool supports progressing full waterflood expansion 24

25 Waterflood and Enhanced Oil Recovery Scope Select Pools OOIP (MMbbl) Cumulative production to YE 2016 (MMbbl) P+P Reserves booked at YE 2016 (MMbbl) Implied Recovery Factor (%) Expected Primary Recovery (5-8% (MMbbl) Potential with Secondary Recovery and EOR (10-15%) (MMbbl) Sparky I2I % Upper Mannville B (1) % Upper Mannville T8T % Total % (1) Reflects former Upper Mann A & B pools currently merged AER 4 to 6 X Large scope for increased reserves and value through waterfloods and possible polymer floods 25

26 Shallow Gas Disposition Summary Closed Oct 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) Funds Flow: $5-10 MM/year Op Costs: 2016 Pre: $47 MM vs Post: $37 MM 2017 Pre: $47 MM vs Post: $19 MM G & A: 2016 Pre: $19 MM vs Post: $17 MM 2017 Pre: $17 MM vs Post: $10 MM TPP Reserves: (14 MMboe) NPV(10) TPP: $6.5 MM Future Development Capital: $7 MM Well Count: 2,952 vs 585 ARO Liabilities (excl salvage): $123 MM vs $35 MM LLR: 2.1 vs 4.4 Net Asset Value (PV10): $28.5 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 Disposed Assets 2,221 net wells; 353,777 net undeveloped acres 584 producing, 910 shut-in, 727 abandoned wells POC trust interest retained on GOB Accretive to Perpetual on all financial and value metrics Material decrease in production & reserves offset by increase in cash flow & value 26

27 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 ~ 6 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 underway in Q & 2017 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 Optimal development plan focuses on intense program approach to recompletion/workovers combined with abandonment and reclamation projects 27

28 Viking/Colorado Shallow Shale Gas Viking/ Colorado Hz Pilot Competitor Hz Drills >885 BCF Resource In Place OGIP estimated average 5.9 Bcf/section Viking > 342 BCF potential recoverable resource Assumes HZ development at 2 wells/section Probable opportunity to double to 4 wells/section Booked reserves 1.3 Bcf PPNP booked in recompletions Proven development & capital commitment could drive substantial future bookings Colorado > 245 BCF potential recoverable resource Assumes HZ development at 2 wells/section Probable opportunity to double to 4 wells/section. Over 150 net prospective sections Plant & pipeline infrastructure Develop with Viking & Mannville tight sands to reduce costs & enhance economics 2015 Evaluated competitor activity to further refine geologic model, frac design, performance & costs expectations Encouraging risk/reward at >$3/GJ gas price Q4 2016/2017 Executing Viking/Colorado 2 well horizontal pilot Encouraging results from competitors Testing play with HZ drills in Q Full scale development improves netbacks on existing shallow gas operations 28

29 KEY PRIORITY #3 ADVANCE HIGH IMPACT OPPORTUNITIES

30 Bitumen N. Alberta Oil Sawn Lake Perpetual Panny LEAD Pilot Andora Sawn Lake Perpetual OS Leases Perpetual Panny Pilot Experimental Primary Projects Thermal Projects Other Projects Major Oil Pipelines Panny Hoole North & South Liege CNRL Woodenhouse CNRL Wabasca N. Cavalier Hoole Husky McMullen Sunshine Harper Husky McMullen Thermal Pilot Sunshine Athabasca Oil West Ells Dover West Carb Pilot Husky Saleski Carbonate Pilot Laricina Saleski Carbonate Pilot Koch Muskwa CNRL Brintnell Crescent Pt. Brintnell CNRL S. Wabasca Sunshine Legend Lake CNRL S. Brintnell Wabasca Husky Amadou Brion Dover Koch Dunkirk CNRL McLaren CNRL Cherpeta Prosper Rigel Sunshine Thickwood OSUM Sepiko Kesik Cenovus Pelican Lake Cenovus Pelican Lake Grand Rapids Black Pearl Blackrod Pilot Ells Southern Pacific STP McKay Marathon Birchwood Grizzly Thickwood Suncor Dover Demo Suncor MacKay River 396 net sections (253,000 net acres) of oil sand leases Various formation targets and ultimate recovery methods 7 potential project areas with varying potential Over 3 billion bbls OBIP independently recognized at Liege and Panny 278 MMbbl contingent resource 467 MMbbl additional prospective resource Sold 37 net sections of select oil sands leases for $6.1 million in Q Retained 1% GORR Bitumen lands represent large resource in place and material option value 30

31 Bitumen Panny Bluesky 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 LEAD Pilot Panny Bluesky Resource Assessment 755 MMbbl Discovered OBIP (McDaniel 2011) Reservoir simulation model supports >50% recovery factor Resource to support >25,000 bbl/d commercial project for years Excellent reservoir quality in Bluesky homogeneous estuarine sand facies Roads Natural Gas Pipeline Oil Well Effluent Pipeline Perpetual Gas Plant Perpetual Oil Sands Rights Other Perpetual Lands Experimenting with lower energy intensity extraction technologies than traditional steam-based thermal methods to mobilize bitumen LEAD Pilot Phase 1 now operating Phase 1 utilizes 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 Ongoing IETP funding reimbursed 30% of all capital and operations costs through YE

32 LEAD Process Technology Pilot Low Pressure Electro-thermally Assisted Drive First stage of pilot single well Cyclic Heat Stimulation currently operating 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 Commenced electrical heating in October 2015; First production in March 2016 Four cycles executed through 2016 of varying heat stimulation and solvent parameters Exceeded cumulative oil production expectations by >100% Second stage of pilot 2018 Guided by first stage learnings and economic viability assessment to be scoped in 2017 Initial 10,000 to 15,000 bbl/d development if pilot successful Drilling-intensive technology allows for scalability without large upfront capital commitment of steam projects LEAD Pilot Stage 2 Configuration Top Gas Oil Heaters / Injectors Producer Electrical heating cable with water injection for mobility and pressure support 32

33 KEY PRIORITY #4 OPTIMIZE BALANCE SHEET FOR GROWTH

34 Debt Reduction (1) December 31, 2016 estimate ~$41 MM (1) 2015 Asset Transactions West Edson swap 6.75 million TOU shares Closed April 2015; $38.50/share $ 258 million Sold 0.5 million for $16 million proceeds in Q & Q Fee Simple land sale $ 21 million Royalties & seismic - Closed April Asset Transactions Oil Sands leases 37 sections Closed March 2016 Warwick Gas Storage (30% Psp) $ 6.1 million $ 23 million Proceeds include reduction of net share of partnership debt ($2.5 million) Shallow Gas Disposition Deferred Purchase Price Balance Sheet Transactions Convertible Debenture Settlement $ 35 million Issued 11.5 million (post-consolidation) PMT shares Dec 31/15 Rights Offering $ 25 million Issued million (post-consolidation) PMT shares Jan 18/16 Margin Loan Repayment $ 31 million In conjunction with TOU Share/Note swap (May 2016) High Yield notes for TOU share exchange 4.4 million TOU shares swapped for $215 million Senior Notes $114.1 million 2018 Senior Notes retired; $36 million remaining $100.3 million 2019 Senior Notes retired; $25 million remaining $ 214 million Targeting additional asset sales for further debt reduction and improved liquidity 34

35 INVESTMENT THESIS EXTREME DISCOUNT TO NET ASSET VALUE LEVERAGED TO GAS PRICE RECOVERY AND BEST IN CLASS GAS E&P (TOU)

36 Proved and Probable (MMboe) Reserve Distribution by Geography and Play Type 120, ,000 80,000 60,000 East Edson West Edson Elmworth 40,000 Other Deep Basin Mannville Heavy Oil 20,000 Eastern Shallow Gas Post-Oct 1, 2016 Shallow Gas Disposition, over 93% of 2P reserves at East Edson 36

37 MMboe Millions Year over Year reserves and value Total Proved Plus Probable Reserves PV 10 TPP Reserves 310 Despite a sizable decrease in reserves related to the Shallow Gas Disposition, the NPV of 2P reserves increased by 21%, despite lower future commodity prices

38 Reserve distribution by category - Year-End 2016 Total: 61.3 MMboe P+PDP P+PDNP P+PUD P+PDP P+PDNP Total: $381 Million P+PDP P+PDNP P+PUD P+PDP P+PDNP P+PDP P+PDP P+PUD P+PDNP P+PUD Mannville Eastern Shallow Gas Deep Basin P+PDNP Future development capital (FDC) decreased $91 million from YE 2015 to $368 million Dispositions accounted for just $7.9 million of the decrease Remaining reduction relates largely to future development of 2P reserves at East Edson Improved costs to reflect reduced labor and better drilling efficiencies related to successful drilling program design changes Shift of 8.5 net wells from reserves to inventory as improved type curve dictates fewer wells forecast to be required to execute McDaniel s notional 9 year development plan 2P undeveloped reserves stand at 74% of total 2P reserves with $35 - $40 million annually to drill to fill East Edson infrastructure at current capacity 38

39 Sum of the parts Year-End 2016 (1) Year-end 2016 reserves based on McDaniel reserves and pricing (2) 1.85 million TOU $35.91/share as per YE 2016 (3) Includes appreciation of TOU shares based on 12 month TOU consensus target price of $ 40.10/share Trading materially below reserve-based net asset value 39

40 WTI (US$/Bbl) 2017 Projected Funds Flow 2017 Forecast Production 10,700 boe/d 54 MMcf/d gas 1,700 bbl/d oil and NGL Projected 2017 Funds Flow (1)(2)(3) ($ millions) 2017 AECO (Cdn$/GJ) (1) As per December 8, 2016 disclosure; forward average AECO and WTI prices for calendar 2017 as of December 8, 2016 were $3.14 per GJ and US$54.10 per bbl, respectively (2) Embeds net value of $2.58/GJ put commitment and $2.81/GJ call option for shallow gas disposition arrangements (3) Base funds flow forecasts do not incorporate current commodity hedges entered into after December 8, 2016 which mitigates downside risk and upside exposure on ~50% of production (see commodity hedge summaries) 2017 funds flow forecast at current commodity prices ~ $ $0.70/share (~ $0.60/share pro forma financing transactions) 40

41 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 higher netback production in asset mix Track Record of Operational Performance Execution and operational excellence in chosen strategies Multiple Levers to Manage Balance Sheet Liquidity established to manage debt obligations Credit transactions provide liquidity to manage future TOU-share based loans and 2018 senior notes Pursuing further asset dispositions to continue to reduce outright debt leverage Expected growth in available liquidity through credit facility expansion Value Trading well below Reserve-Based Net Asset Value Net enterprise value ~4 times 2017 & 2018 funds flow at strip pricing Tremendous leverage to gas prices with asset mix, Shallow Gas disposition call option and TOU exposure High impact value potential from medium to long term assets Spectrum of opportunities for value creation upon emergence from bottom of commodity price cycle 41

42 ADDITIONAL INFORMATION Sue Riddell Rose President & CEO Bill Hahn Interim VP Finance and CFO Claire Rosehill Investor Relations TOLL FREE PHONE FAX 3200, 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 42

43 Commodity price risk management Natural gas Natural Gas Contracts All contracts post-december 8, 2016 funds flow sensitivity Term Volumes at AECO (GJ/d) Average Price ($/GJ) (1) Market Price ($/GJ) (2)(3) Type of Contract January ,500 $3.16 $3.33 Financial January ,000 $3.26 $3.33 Physical February ,000 $3.29 $2.67 Physical March ,000 $3.11 $2.65 Physical April Dec ,500 $3.16 $2.65 Financial April Dec ,000 $3.14 $2.74 Physical (1) All contracts post-december 8, 2016 funds flow sensitivity (2) Average price calculated using weighted average price for net open contracts (3) Market prices are based on forward prices as of market close on January 11, 2017 (4) January 2017 contracts settled at $3.33/GJ Shallow gas disposition - related marketing contracts Closed contracts post - Dec 8 Perpetual retained exposure to increases in natural gas prices through to August 2018 with a call on 33,611 GJ/d at $2.81/GJ Perpetual will provide a floor price at $2.58/GJ on 33,611 GJ/d through August As such, Perpetual has purchased a put through to March 2018 at a cost of $0.295/GJ which settles monthly through a third party marketing company and has adjusted funds flow forecasts accordingly. Term Volumes at AECO (GJ/d) Average Price ($/GJ) (1) Profit ($ 000s) Type of Contract January ,611 $3.24 $448 Financial February ,611 $3.29 $452 Financial (1) All contracts post-december 8, 2016 funds flow sensitivity Close to 50% natural gas price downside protection for 2017 Optionality on shallow gas disposition marketing arrangements with $2.81/GJ call 43

44 Commodity price risk management Oil Costless collar oil sales Term Volumes (bbl/d) Floor Price (USD$/bbl) Ceiling Price (USD$/bbl) Market Price (USD$/bbl) (1) Type of Contract Jan Dec $50.00 $59.40 $55.33 Collar Feb Dec $50.00 $61.50 $55.56 Collar (1) Market prices are based on forward WTI oil prices as of market close on January 11, 2017 (2) All contracts post-december 8, 2016 funds flow sensitivity Basis differential contracts between WTI and WCS Term Volumes (bbl/d) WTI-WCS differnetial (USD$/bbl) Market Price (USD$/bbl) (1) Type of Contract Feb Dec ($15.40) ($15.52) Financial (1) Market prices are based on forward WTI oil prices as of market close on January 11, 2017 (2) All contracts post-december 8, 2016 funds flow sensitivity Close to 50% oil price downside protection for