CAPP SCOTIABANK APRIL 12, 2016 BOLD IDEAS FOR ENERGY

Transcription

1 CAPP SCOTIABANK APRIL 12, 2016 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," "2015 through 2016" and similar expressions are intended to identify such forwardlooking statements. Such statements include, but are not limited to, statements pertaining to: Perpetual's business diversification and price risk management strategies which include the transitioning from shallow gas assets to resource-style, growth orientated oil and NGL assets and divestitures to optimize value and decrease debt; projected economics for various projects; future capital expenditure levels; expected compliance with credit facility covenants in 2015 and 2016 the top strategic priorities for 2015 and beyond. 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 capital, increases in the costs of rented or contracted equipment, increases in laborcosts, 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 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 back 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 promulgated by rule-setting bodies; the amount of future abandonment and reclamation costs, asset retirement and environmental obligations; expected realization of gas over bitumen royalty adjustments; 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 effectsonourbusinessandoperationsandontheforward-looking statements contained herein. Also included in this presentation are estimates of Perpetual's consolidated net debt and 2015 funds flow, which are based on the various assumptions as to production levels, capital expenditures, and other assumptions (including price assumptions for natural gas and oil) and the effects of the West Edson property disposition. To the extent any such estimate constitutes a financial outlook, it was approved by management and the Board of Directors of Perpetual on March 12, 2015 and is included to provide readers with an understanding of Perpetual's anticipated funds flows based on the capital expenditure and other assumptions described herein and readers are cautioned that the information may not be appropriate for other purposes. 2

3 Perpetual Energy Inc. Common shares o/s 52.4 million Management ownership ~49% Share price (1) $ 1.25 Market capitalization $ 66 million Total net debt (2) Net bank debt (2) Financing arrangement (3) Senior unsecured notes TOU Shares 6.25 $25.78/share Enterprise value $ 167 million $ 32 million $ 21 million $ 275 million ($ 161 million) $ 233 million (1) Five day weighted average price (2) Estimated current bank debt, net of working capital; includes reserve-based facility and TOU share-based margin loan (3) Settle amount at November 2016 maturity; Secured by 1 million of the TOU Shares 3

4 Diversified portfolio for value creation SHALLOW GAS LIQUIDS- RICH GAS HEAVY OIL BITUMEN OTHER Eastern Alberta Conventional Viking / Colorado Shallow Shale Gas Edson Wilrich Greater Edson Multi-zone Edson Secondary Zones Deep Basin Exploration Mannville Mannville EOR Heavy Oil Exploration Panny Bluesky Liege Grosmont & Leduc Other Warwick Gas Storage Waskahigan Duvernay GOB Technical Solutions Tight Oil and Gas Exploration Spectrum of opportunities to optimize value through variable commodity cycles 4

5 Operating profile Eastern Alberta Conventional shallow gas Mannville heavy oil Bitumen Warwick gas storage 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) 19,706 boe/d 104 MMcf/d 2,337 bbl/d 77.8 MMboe LIQUIDS-RICH GAS East Edson Other Deep Basin SHALLOW GAS Legacy conventional assets, Tight shallow gas HEAVY OIL Mannville BITUMEN Panny, Liege, Other GAS STORAGE Warwick Reserve to Production Ratio (P+P) (RLI) (2) Bitumen (3) Warwick Gas Storage Capacity (gross) (4) Tourmaline Oil Corp. Shares 6.25 million (5) (1) Year Ended December (2) Year Ended December (3) 425 sections at year end 2015; Internal contingent resource estimate (4) 30% ownership interest (5) April 8, 2016 market price of $25.78/share 12 Years 279 MMbbl 19.1 Bcf ~161 million 5

6 Portfolio management strategy 2016 CASH FLOW GENERATORS Maximize Cash & Preserve Value Conventional shallow gas Warwick Gas Storage Mannville heavy oil PROVEN DIVERSIFYING GROWTH STRATEGIES Re-invest to mitigate declines Edson liquids-rich gas Mannville heavy oil Waterflood MEDIUM AND LONG TERM VALUE STRATEGIES Optimize & Advance Mannville heavy oil EOR Viking/Colorado shale gas Waskahigan Duvernay Tight oil & gas exploration Bitumen Panny / Liege Preserving value and advancing strategic plan 6

7 2016 Top four strategic priorities 1. Reduce debt & restore cash flow 2. Grow value & scope of Greater Edson liquids-rich gas 3. Maximize value potential of Eastern Alberta assets 4. Advance high impact opportunities Strategic priorities focus our activities 7

8 KEY PRIORITY #1 REDUCE DEBT AND RESTORE CASH FLOW

9 Debt reduction ~$167 MM (1) 2015 Asset Transactions West Edson swap $ 258 million 6.75 million TOU shares Closed April 1 st 2015; $38.50/share = $ 258 million Sold 0.5 million for $ 16 million proceeds 6.25 million remaining; $ 25.78/share = $ 161 million Fee Simple land sale $ 21 million Royalties & seismic Closed April 10/2015 Recapitalization Transactions Convertible Debenture Settlement Issued 230 million PMT shares $ 35 million Closed Dec 31/2015 Rights Offering Issued 665 million PMT shares Closed Jan 18/2016 $ 25 million (1) Estimate April Asset Transactions Oil Sands leases 37 sections Closed March 2016 $ 6.1 million Targeting additional asset sales for further debt reduction 9

10 West Edson transaction summary Swap of West Edson property for 6.75 million Tourmaline Shares 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 Transaction Rationale Swap for exposure to upside potential in West Edson but also well-funded Alberta Deep Basin and BC Montney portfolio through TOU shares Improve liquidity Strengthen financial position and optionality Bolsters ability to manage future debt obligations Allows flexibility to fund capital program to capture inherent value in East Edson and other high impact assets Enhanced lending value for TOU shares relative to West Edson reserves (20% proved producing) Improves cost and access to capital to pursue new strategic initiatives Enhance ability to manage downside risk in low commodity price environment Neutral to reserve-based NAV discounted at 10% Reduce net debt, considering TOU shares as a direct offset Current Holdings 6.25 million MTM value of $161 million Desire to retain maximum exposure 10

11 Recapitalization transactions Extend Maturities Bank debt maturities extended to October 31, 2016 Revised financial covenants provide increased flexibility and stability Improve Liquidity $25 million of new equity capital through Rights Offering $18 million from New Financing Arrangement increases liquidity through securitization of 1 million Tourmaline shares Debt Reduction $35 million reduction of debt through settlement of Convertible Debentures through issuance of PMT Common Shares Preserve Asset Base to Maintain Value Potential Allows us to maintain attractive current assets and operations Full upside to Tourmaline shares preserved Recapitalization transactions enhance balance sheet strength

12 Post-Recapitalization balance sheet Net Bank Debt: ~$32 million (1) Borrowing base on credit facility - $62 million $20 million reserve-based loan Opened up for redetermination due to falling commodity prices March 2016 Historically calculated net of $40 million grind for senior notes $42 million margin loan secured by 5.25 million TOU shares Single one time only draw (no revolving feature) Interest rate = prime % (~6.45%) Loan to value ratio = 33.3% (3.0 times margin coverage) Term margin loan matures on October 31, 2016 Senior Unsecured Debt: Face Value $275 million; Market Value ~$150 million Series Amount Outstanding Coupon Rate Maturity Date Current Trading Price Current Yield Market Value 8.75% 2018 $150 million 8.75% March 2018 $ % $ % 2019 $125 million 8.75% July 2019 $ % $66.3 New Financing Arrangement: $21 million Established downside protection on 1 million TOU Shares to enhance collateral lending value Carrying amount $18 million - All costs prepaid Matures November 2016 TOU Shares: 6.25 million $25.78/share = $161 million Total Debt Net of TOU Shares: ~$167 million (1) Current Estimate March 2016 TOU Shares provide significant offset to future debt obligations 12

13 2015/2016 Capital spending Activity Capital Q1 Q2-Q4 Total West Central Liquids-Rich Gas 6 gross (4.5 net) wells West Wolf Facility $ 67.5 MM $ 5 MM 1 gross (1 net well) $ 2.3 MM $ 7.3 MM Mannville Heavy Oil Waterflood facilities $ 1.4 MM $ 1 MM $ 0.1 $ 0.2 MM Eastern Shallow Gas and Other Recompletions/ Workovers/ Optimization $ 1.9 MM $ 0.1 MM $ 0.7 MM $ 0.8 MM Panny Pilot 2 gross (2.0 net) $ 4.6 MM $ 0.0 MM $ 0.0 MM Total $ 75.4 MM $ 5.2 MM $ 3.1 MM $ 8.3 MM 2015 Excludes abandonment and reclamation spending of $ 7.2 Million 2016 Excludes abandonment and reclamation spending estimate of $ 2.5 Million Adjustable capital program focused on mitigating declines and net cash flow generation 13

14 KEY PRIORITY #2 GROW VALUE AND SCOPE OF GREATER EDSON LIQUIDS-RICH GAS

15 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 Pre 2014 Drill 2014 Drill 2015 Q1 Drill 2016 Q1 Drill (1) 2016 Q3/Q4 Drill (3) 2017 Proposed Drill (6) East Edson JV Lands Inventory of 138 gross (123 net) undrilled locations 87 gross (79 net) booked in reserve report

16 East Edson type curves Projected Economics per SW Drilling Location McDaniel SW Type Curve McDaniel NE Type Curve Capital (D,C & T) ROR F&D Capital Efficiency Payout $ 4.8 MM $ 2.4 MM 33% BT $ 8.50 / boe $9,000 boe/d 2.6 Years D e c 3 1, Recycle Ratio 1.7 Assumptions (McDaniel YE 2015) Year 1 Pricing $2.55/ GJ (Aeco); $32.23/ bbl NGL Operating Costs Well Depth Type Curve 2P Reserves $2.72/ boe (first year) 4,600 M HZ; 2,500 TVD IP 6.5 MMcf/d 1 year exit rate 1.8 MMcf/d 11.5 bbl/mmcf NGL/condensate 3.4 Bcfe per well Average well consistently beats McDaniel Type Curve, even though rates for most wells were curtailed pending new plant commissioning in early July 2015, and expansion in September JV wells drilled to complete all near term commitments, with 3 remaining wells required by Well performance above type curves. 16

17 Greater Edson production growth 90 Greater Edson Daily Production TCPL Restrictions 60 Gas Rate (Mmcf/d) Jan 14 Mar 14 May 14 Jul 14 Sep 14 Nov 14 Jan 15 Mar 15 May 15 Jul 15 Sep 15 Nov 15 Jan 16 Mar 16 Production from West Edson swap for TOU shares effectively replaced upon start-up of new East Edson Plant in July 2015 Edson Ansell 17

18 Greater Edson liquids-rich gas play performance 14,000 12,000 16,000 14,000 40% net production growth in 2014 Driven by West Edson expansion from 15 to 30 MMcf/d net Ramp up to fill existing East Edson facilities with JV drilling 30 MMcf/d by year end 2014 Boe/d 10,000 8,000 6,000 12,000 10,000 8,000 6,000 Cumulative Production (MBoe) 136% net production growth in 2015 Growth despite swap of West Edson (30 MMcf/d net plus associated liquids) effective April 1 Constructed new 30 MMcf/d East Edson plant onstream July 2015 Expanded East Edson plant to 45 MMcf/d September 2015 Infrastructure ownership drove low Q4 op costs of $2.46 per boe Drilled to fill East Edson facilities and transportation contracts 30 MMcf/d in H1 ramping up to 60 MMcf/d in H2 Improved results required 5 less wells in 2015 than forecast to achieve capacity through the year 4,000 4,000 Preserving Value in 2016 low gas price environment Current capital plan includes 1 drill and complete 2,000 2,000 Continued growth potential in 2017 through 2018 Drill to fill existing infrastructure as appropriate E East Edson West Edson East Edson Up to 75 MMcfe/d capacity (full year effect) Potential further expansion at East Edson plant of additional 15 MMcfe/d to take area capacity to 90 MMcfe/d Secondary Viking, Notikewin and Fahler horizontal development potential supported by 3D seismic exploration Infrastructure and inventory in place for continued growth 18

19 KEY PRIORITY #3 MAXIMIZE VALUE OF EASTERN ALBERTA ASSETS

20 Eastern Alberta Conventional heavy oil Mannville 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 cost HZ development $1 - $1.2 MM single or dual lateral HZ well Average initial rate ~80 bbl/d 2015 Capital activity $2.2 MM of waterflood expansion Additional injection conversions in 3 pools Source water conversion to supply additional water Facility and pipeline expansion Current Injectors 2016 Recommendations 2016 Capital activity plans Up to $1.2 MM of waterflood expansion Additional 4 injection conversions Facility and pipeline expansion to optimize operating costs * 6 of 8 pools shown Capital focused on waterflood implementation in 5 main pools Drilling deferred due to low oil prices to preserve development inventory 20

21 Mannville heavy oil value potential Projected Economics Per Well Lloyd Sparky Capital (D,C & T) $1.2 MM $1.2 MM 10 % $1.6 MM $0.8 MM ROR ~ 200% ~ 95% F&D $13.50 / Boe $20.50 / Boe Payout 0.7 Year 1.2 Year Capital Efficiency ~$15,000/Boe/d ~$25,000/Boe/d Recycle Ratio Pricing Operating Costs Average Well 2P Reserves Royalties Assumptions (McDaniel Year End 2013) $68.90/bbl Wellhead heavy price WTI $US95/bbl, WCS $US23.5/bbl, offset $7.60/bbl $6.23/Boe (first year) & $12.60/Boe (lifetime) Lloyd IP 120 bbl/d to 75 bbl/d after year 1 Sparky IP 85 bbl/d to 44 bbl/d after year 1 90 Mbbl per Lloyd well 60 Mbbl per Sparky well 5% for first 18 months on Crown; variable on Freehold Oil over shakers while drilling Sparky development pad HZ pad site Highly profitable in oil price recovery 21

22 Waterflood and enhanced oil recovery Mannville I2I Waterflood Pool Sparky Mid Type Log 100/ W4/00 > 24 % DENSITY POROSITY 6 m OIL PAY Sparky Mid Sand Working Interest 66.7% OOIP: 38 MMbbl Cum Prod n + McDaniel P+P: 1.5 MMbbl (4% recovery factor) technical recovery 19 Horizontals drilled to date 11 infill locations remain Implementing Waterflood 7 injectors converted in 2013/ injection conversion Oil bbl/d Actuals Upper Mannville I2I Waterflood Update Water Injection Start Oil Rate Oil Base Forecast Internal Forecast McDaniel YE 2015 Internal Forecast McDaniel YE 2015 Base Forecast 0 1/1/2012 1/1/2013 1/1/2014 1/1/2015 1/1/2016 1/1/2017 1/1/2018 Waterflood injection optimization through 2015 showing increasing oil response 22

23 Early waterflood response NE portion Mannville B Pool Lower Channel Sand Water Injection Start Oil Rate Oil Base Forecast McDaniel YE2015 Internal Forecast Oil Rate, bbl/d Actuals Internal Forecast McDaniel YE Base Forecast 0 1/1/2013 1/1/2014 1/1/2015 1/1/2016 1/1/2017 1/1/2018 Oil Rate, bbl/d Single pattern Mannville B Pool Regional Lloyd Sand Actuals Base Forecast Water Injection Start Oil Rate Oil Base Forecast McDaniel YE 2015 Internal Forecast Internal Forecast McDaniel YE /1/2013 1/1/2014 1/1/2015 1/1/2016 1/1/2017 1/1/2018 Positive initial waterflood response in Mannville B pool supports progressing full waterflood expansion 23

24 Waterflood and enhanced oil recovery scope Select Pools OOIP (MMbbl) Cumulative production to YE 2015 (MMbbl) P+P Reserves booked at YE 2015 (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 24

25 Conventional shallow gas Legacy asset base characteristics Northeast and East Central Alberta Cretaceous and Devonian sweet shallow gas < 800m Current production ~ 50 MMcf/d Belly River Viking Base declines < 10-15% Multiple stacked zones and play types Extensive plant and pipeline infrastructure with material unutilized capacity Low base royalty rate of ~ 5% at <$5/Mcf High fixed operating costs driven by municipal taxes and large number of low volume wells Grand Rapids Lower Mannville Pre Cretaceous Unconformity Netbacks highly leveraged to natural gas prices Operational Focus Reduce ARO Facility optimization projects, workovers and uphole recompletions payout in months Low cost production and reserves adds (<$10,000/boe/d; <$1.00/Mcf) Drive fixed and variable operating cost reductions Metering, municipal taxes, scaled-back operational approach, ARO Prospecting for tight reservoirs in high resource potential traps that now can be exploited with horizontal wells and multi-stage frac technologies Reduced asset retirement obligation by close to $50 million in 2015 through multi-faceted, full life cycle operating approach 25

26 Viking/Colorado shallow shale gas Competitor horizontal drills Belly River Play Fairway Cardium/ Colorado Wells Perpetual Lands Historical Viking Reserves Proved Undeveloped Probable Undeveloped Reserves Proven Non-Producing >130 TCF Resource In Place OGIP estimated average 16 Bcf/section m gas saturated shale section 6 prospective zones Viking Booked reserves 12 Bcf PNP booked in recompletions Historical 2P reserves of 100+ Bcf removed from bookings due to price revisions Proven development & capital commitment could drive substantial future bookings Colorado Group > 1 TCF potential recoverable resource HZ development at ~8+ wells / section Over 1,200 net prospective sections Extensive plant & pipeline infrastructure Develop with Viking & Mannville tight sands to reduce costs & enhance economics 2015 Evaluated competitor activity to further refine frac design, performance & costs expectations Encouraging in $3+ gas price environment 2016 Horizontal pilot ready to execute Encouraging results from competitor operations Full scale development improves netbacks on existing shallow gas operations 26

27 KEY PRIORITY #4 ADVANCE HIGH IMPACT OPPORTUNITIES

28 Warwick gas storage 40 Bcf Storage Reservoir Delta Pressure to 47 Bcf 10 Bcf base reserves cushion gas in place Up to 25 Bcf potential working gas capacity 1.2 to 1.5 cycle facility WGSI Leases Well Site Pad Storage Facility Pipeline Horizontal Wells 2012 Hz Wells TCPL Pipeline Commercial Park and Loan business 30 to 50 year life Grass Roots Development Existing depleted gas pool Facility Construction Bcf working gas capacity Expansion Potential Delta pressuring to increase working gas to 24.5 Bcf with minimal incremental costs 30% Perpetual Interest Manage WGS LP for annual fee Diversified Cash Flow 2012 & 2013 ~$11 million/year gross Electrical fire upset operations and reduced cash flow in 2014 & projected cash flow ~$10 million gross Non-depleting, long life, diversifying asset Cash flow growth potential as spreads normalize to historical levels 28

29 Waskahigan Duvernay volatile oil play Richer/Volatile Oils 13-1 Cum to date 84 MSTB Oil (17 months) Leaner/Gas Condensates Simonette Leduc Reef PMT ( 35% WI) PMT (100% WI) AOC Drills AOC Licenses Apache Licenses Chevron Drills Chevron Licenses CIOC Drills Encana Drills Encana Licenses Duvernay Net Pay Contour Interval = 5m Deep Valley Gas Plant Volatile oil/high liquids gas play proven prospective on PMT acreage Monitoring test well & play development to evaluate costs and performance AOC Farm-in: Drilled & completed W5 PMT retains 35% in 6 sections & 100% in 3.75 sections Land continued to Production Onstream Dec 1, 2015 Average daily production December 289 Bbl/d Condensate 277 Mcf/d Gas ~21 Bbl / MMcf C5+ ~93 Bbl / MMcf C3/C4 Downhole pump installation March 2016 to optimize production Full Development Potential: OOIP > 86 MMbbl (44 net) ~8 wells per section 64 gross (32 net) wells 29

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 Bitumen lands represent large resource in place and material option value 30

31 Bitumen Panny Bluesky Low rate cold flow 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 LEAD Pilot Phase 1 now operating Phase 1 consists of a single horizontal well Heating commenced in October 2015 First production in March 2015 Production is exceeding expectations by >100% IETP funding reimburses 30% of all capital and operations costs Experimenting with lower energy intensity extraction technologies than traditional steam-based thermal methods to mobilize bitumen 31

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 oil production in March 2016, currently exceeding cumulative oil production expectations by >100% Second stage of pilot an additional $20 to $30 million Guided by first stage learnings 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 INVESTMENT THESIS EXTREME VALUE DISCOUNT TO ASSET VALUE LEVERAGED TO GAS PRICE RECOVERY AND BEST IN CLASS GAS E&P (TOU)

34 Sum of the parts NAV Year End 2015 reserves and inventory with market to market adjustments for TOU share price appreciation, rights offering, March 2016 debt and share consolidation (1) 6.25 million TOU $28.50/share as at March 23, 2016 (2)(3) Includes appreciation of TOU shares based on 12 month TOU consensus target price of $ 35.68/share Trading materially below reserve-based net asset value 34

35 Key investment highlights High Quality Assets Asset base repositioning for resource-style and diversification successful Edson Wilrich liquids-rich gas inventory well-defined 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 Exposed to premium asset base through TOU share ownership Alberta Deep Basin, BC Montney & Peace River High Charlie Lake plays Track Record of Operational Performance Execution and operational excellence in chosen strategies Multiple Levers to Manage Balance Sheet 80% of debt has term into 2018 and beyond Multiple levers available to manage debt obligations Pursuing further asset dispositions to continue to reduce outright debt leverage TOU shares provide offset for future debt obligations Recapitalization transactions create modest liquidity to execute prudent capital spending program and survive commodity price collapse Value Trading below Reserve-Based Net Asset Value through Equity Transaction Uncertainty Net asset value materially connected to TOU share value at 50% of enterprise value High impact value potential from medium to long term assets Tremendous leverage to oil and gas price cycle recovery in 2016 and beyond Spectrum of opportunities for value creation upon emergence from bottom of commodity price cycle 35

36 ADDITIONAL INFORMATION Sue Riddell Rose President & CEO Cam Sebastian Vice President, Finance & CFO 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 36